Public Service Co Of Colorado 10-K 2005 FY Annual report

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, 2005
	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 if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. o Yes or No ý

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). o Large accelerated filer o Accelerated filer ý Non-accelerated filer

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

As of Feb. 20, 2006, 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 2006 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).

INDEX

General Electric Utility Pending Regulatory Matters

Trading Operations

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

This Form 10-K is filed by Public Service Co. of Colorado (PSCo). PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC). This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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 that allowed PSCo to equally share between electric customers and shareholders certain fuel and purchased energy costs and expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs was amortized over the period June 1, 2002 through March 31, 2005.

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IAC	Interim adjustment clause. A retail adjustment clause that allowed 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	Quality of Service Plan. 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

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

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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.

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COMPANY OVERVIEW

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

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

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

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

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

In 2005, Xcel Energy’s 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 — 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 through 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. Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition.

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.

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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.

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

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

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

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

•Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary North American Electric Reliability Council (NERC) structure, and requiring the ERO to establish mandatory reliability standards and imposition of financial or other penalties for violations of adopted standards; NERC is expected to apply to become designated as the ERO later in 2006;

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

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

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

PSCo generally supports the regulations adopted or proposed by FERC to date, but cannot predict the ultimate impact the new regulations will have on its operations or financial results.

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

On Feb. 7, 2005, Xcel Energy on behalf of itself and the utility subsidiaries filed an updated market-power analysis that applied FERC’s new standards. This analysis demonstrated that PSCo did not pass the pivotal supplier analysis in its own control area and all adjacent markets or the market share analysis in its own control area.

In June 2005, the FERC initiated a proceeding to investigate PSCo’s market-based rate authority within its own control area. The refund effective date that has been set as part of that investigation for such sales is Aug. 12, 2005. The FERC required that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order. The latter compliance filing was submitted on July 5, 2005.

On Aug. 1, 2005, PSCo submitted a filing to withdraw its market-based rate authority with respect to sales within its control areas. As part of that filing, PSCo proposed to charge existing cost-based rates for sales into the PSCo control areas. In October 2005, PSCo filed revised tariff sheets to reflect that limitation on its market-based rate authority. The matter is pending before the FERC.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO. Each RTO separately files for

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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.

Ratemaking Principles

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

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

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

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

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

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

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

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

Performance-Based Regulation and Quality of Service Requirements — 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 for 2004 through 2006 with the sharing between customers and shareholders of earnings in excess of a return on equity for electric operations of 10.75 percent;

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

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

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

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

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PSCo established new rates in its general rate case.

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

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

Pending and Recently Concluded Regulatory Proceedings –– FERC

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

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

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

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

FERC OMOI Compliance Audit — On October 28, 2004, the OMOI sent a letter to Xcel Energy stating that OMOI had initiated a routine audit of PSCo compliance with various FERC regulations, including PSCo’s OATT, FERC’s Order No. 889 standards of conduct rules and PSCo’s code of conduct for transactions in power and non-power goods with affiliates

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with market-based rates. Similar compliance audits of other utilities have resulted in compliance orders and, in certain cases, civil penalties. On November 28, 2005, FERC issued an order approving an audit report that recommended certain operational changes but imposed no civil penalties.

Pending and Recently Concluded Regulatory Proceedings–– CPUC

Tie Line Cost Recovery –– On Sept. 20, 2001, the CPUC ruled that only 50 percent of the total cost of the high voltage direct current (HVDC) converter constructed by PSCo in Lamar, Colorado will be allowed in rate base. This facility is part of the 345 KV tie line transmission facilities connecting the PSCo and SPS systems. The CPUC decision resulted in a reduction of potential PSCo rate base of approximately $16.7 million. On April 7, 2005, PSCo filed an application with the CPUC proposing a mechanism that would leave half of the HVDC facility as a non-rate-base asset, but that would generate revenue to recover the cost of the non-rate-base asset on a pay-as-you-go basis. The proposal would involve allocating half of any energy or fuel cost savings derived from buying electricity through the tie line or making sales through the tie line. Alternatively, PSCo stated that it would not object to the entire HVDC facility being placed in rate base. A hearing examiner for the CPUC issued a recommended decision on Nov. 16, 2005, that reasoned that 100 percent of the HVDC converter be placed in rate base. PSCo expects that the CPUC will act on the recommended decision in February 2006.

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

Capacity and Demand

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

	System Peak Demand (in MW)
	2003	2004	2005	2006 Forecast
PSCo	6,419	6,483	6,975	6,751

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

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its 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 the utility’s reserve obligation, to obtain energy at a lower

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cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

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

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

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

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

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

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

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

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

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

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

The settlement agreement also called for PSCo to acquire the remaining resource needs through an all-source competitive bidding process. On Feb. 24, 2005, in conjunction with the approved LCP, PSCo released an All-Source solicitation for new supply and demand-side resources. In May 2005, PSCo received proposals for over 11,000 MW of firm capacity, nearly 4,600 MW of nameplate wind capacity, and almost 900 MW of demand-side management programs. On Dec. 28, 2005 PSCo filed a report with the CPUC detailing the bids received, the bid evaluation process, and the winning bids. PSCo selected bids for approximately 30 MW of DSM resources, approximately 1,300 MW of dispatchable (gas-fired generation) resources and approximately 775 MW of wind generation resources. These bids, together with Comanche 3, and the additional DSM agreed to in the LCP settlement agreement, are expected to meet the Company’s resource needs through 2012.

Renewable Portfolio Standards — In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard for electric service. The new law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources. Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas. Such incremental costs are expected to be recovered from customers. On March 29, 2005, the CPUC initiated a proceeding to determine the rules and regulations required to implement the renewable portfolio standard. The CPUC received numerous rounds of comments with respect to proposed rules, and the CPUC held hearings beginning in August 2005 regarding the rulemaking. The CPUC conducted oral deliberations in early October and determined, among other issues, that compliance with the renewable energy portfolio standard should be measured through the acquisition of

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renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on this issue; that Colorado utilities should be required to file implementation plans, thereby rejecting the proposal to use an independent plan administrator; and the methods utilities should use for determining the budget available for renewable resources. The CPUC issued proposed rules on Jan. 27, 2006. Final rules are expected to become effective by the end of the first quarter 2006.

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

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

Fuel Supply and Costs

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

	Coal				Natural Gas				Average Fuel
	Cost		Percent		Cost		Percent		Cost
2005	$	1.01	85	%	$	7.56	15	%	$	2.00
2004	$	0.89	87	%	$	5.61	13	%	$	1.52
2003	$	0.92	86	%	$	4.49	14	%	$	1.42

See additional discussion of fuel supply and costs under Risks Associated with Our Business under Item 1A.

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

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

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

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

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

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

Commodity Marketing Operations

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

PSCo Electric Operating Statistics

	Year Ended Dec. 31,
	2005				2004				2003
Electric Sales (Millions of Kwh)
Residential	8,390				8,066				8,251
Commercial and Industrial	17,857				17,409				17,307
Public Authorities and Other	234				252				289
Total Retail	26,481				25,727				25,847
Sales for Resale	8,112				8,372				6,594
Total Energy Sold	34,593				34,099				32,441
Number of Customers at End of Period
Residential	1,091,072				1,083,872				1,078,394
Commercial and Industrial	145,520				144,111				144,991
Public Authorities and Other	62,985				66,797				68,452
Total Retail	1,299,577				1,294,780				1,291,837
Wholesale	62				69				70
Total Customers	1,299,639				1,294,849				1,291,907
Electric Revenues (Thousands of Dollars)
Residential	$	760,919			$	672,496			$	686,627
Commercial and Industrial	1,240,697				1,080,660				1,059,143
Public Authorities and Other	38,977				36,257				38,775
Total Retail	2,040,593				1,789,413				1,784,545
Wholesale	416,503				403,155				315,589
Other Electric Revenues	46,932				2,060				17,656
Total Electric Revenues	$	2,504,028			$	2,194,628			$		2,117,790
Kwh Sales per Retail Customer	20,377				19,870				20,008
Revenue per Retail Customer	$		1,570.20		$		1,382.02		$		1,381.40
Residential Revenue per Kwh	9.07			¢	8.34			¢	8.32			¢
Commercial and Industrial Revenue per Kwh	6.95			¢	6.21			¢	6.12			¢
Wholesale Revenue per Kwh	5.13			¢	4.82			¢	4.79			¢

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NATURAL GAS UTILITY OPERATIONS

Summary of Recent Regulatory Developments

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

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

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

The most significant recent developments in the natural gas operations of PSCo are the substantial and continuing increases in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies. From 1995 to 2005, average annual sales to the typical PSCo residential customer declined from 101 Dth per year to 84 Dth per year on a weather-normalized basis. Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.

Ratemaking Principles

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

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

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

Pending and Recently Concluded Regulatory Proceedings

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

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

•Natural gas revenue increase of $22 million;

•Return on common equity of 10.5 percent;

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

•Common equity ratio of 55.49 percent; and

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

Capability and Demand

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

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

PSCo has closed the Leyden Storage Field and is in the monitoring phase of the abandonment process, which is expected to continue until December 2007. See further discussion at Note 12 to the Consolidated Financial Statements.

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

Natural Gas Supply and Costs

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

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

2005	$	8.01
2004	$	6.30
2003	$	4.94

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

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

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

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PSCo Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2005			2004		2003
Natural Gas Deliveries (Thousands of MMBtu)
Residential	91,086			88,726		91,513
Commercial and Industrial	38,475			38,501		41,545
Total Retail	129,561			127,227		133,058
Transportation and Other	118,214			102,139		104,430
Total Deliveries	247,775			229,366		237,488
Number of customers at end of period
Residential	1,130,888			1,111,377		1,089,958
Commercial and Industrial	95,302			94,414		98,066
Total Retail	1,226,190			1,205,791		1,188,024
Transportation and Other	3,728			3,506		3,264
Total Customers	1,229,918			1,209,297		1,191,288
Natural Gas Revenues (Thousands of Dollars)
Residential	$		924,030	$	742,724	$	599,883
Commercial and Industrial	356,374			288,002		240,084
Total Retail	1,280,404			1,030,726		839,967
Transportation and Other	48,630			43,263		43,085
Total Natural Gas Revenues	$		1,329,034	$	1,073,989	$	883,052
MMBtu Sales per Retail Customer	105.66			105.51		112.00
Revenue per Retail Customer	$	1,044.21		$	854.81	$	707.03
Residential Revenue per MMBtu	$	10.14		$	8.37	$	6.56
Commercial and Industrial Revenue per MMBtu	$	9.26		$	7.48	$	5.78
Transportation and Other Revenue per MMBtu	$	0.41		$	0.42	$	0.41

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ENVIRONMENTAL MATTERS

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.

EMPLOYEES

The number of full-time PSCo employees on Dec. 31, 2005 was 2,595. Of these full-time employees, 2,165, or 83 percent, are covered under collective bargaining agreements. See Note 8 to the Consolidated Financial Statements for further discussion. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, provide services to PSCo.

Item 1A — Risk Factors

Risks Associated with Our Business

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

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

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

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

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

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

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

We are exposed to market and credit risks in our generation, distribution, commodity acquisition, short-term wholesale and commodity trading activities. To minimize the risk of market price fluctuations and product availability, we enter into physical and financial contracts to hedge both price and availability risk associated with purchase and sale commitments, fuel requirements and inventories of coal, natural gas, fuel oil and energy and energy related products. However, these contracts

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do not completely eliminate risks, including commodity price changes, market supply shortages, credit risk and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales commitments or increased interest expense.

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

We mark commodity trading derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Quoted market prices are utilized in determining the value of these derivative commodity instruments. For positions for which market prices are not available, we utilize models based on forward price curves. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

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

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

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

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

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

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

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. As discussed above, the litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005 would reduce retained earnings by an estimated $361 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $428 million.

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Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available.

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

We are subject to a number of environmental laws and regulations affecting many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the management of wastes and hazardous substances. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to perform environmental remediations and to install pollution control equipment at our facilities. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We must pay all or a portion of the cost to remediate sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2005, these sites included:

• the site of a former federal uranium enrichment facility;

• the site of former manufactured gas plants operated by us or our predecessors; and

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

In addition, we cannot assure you that existing environmental laws or regulations will not be revised or that new laws or regulations seeking to protect the environment will not be adopted or become applicable to us or that we will not identify in the future conditions that will result in obligations or liabilities under existing environmental laws and regulations. Revised or additional laws or regulations which result in increased compliance costs or additional operating restrictions, or currently unanticipated costs or restrictions under existing laws or regulations, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

Recession, grid disturbances, acts of war or terrorism could negatively impact our business.

The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any economic slowdown or fluctuating energy prices. However, such impact could have a material adverse effect on our financial condition and results of operations.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the Aug. 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause changes in the insurance markets, force us to increase security measures and cause disruptions of fuel supplies and markets, particularly with respect to natural gas and purchased energy. The possibility that infrastructure facilities, such as electric generation, transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of war may affect our operations. War and the possibility of further war may have an adverse impact on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets as a result of war may also affect our ability to raise capital.

Further, like other operators of major industrial facilities, our generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.

The insurance industry has also been affected by these events. To date, we have been able to obtain insurance at satisfactory levels and terms; however, the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

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Reduced coal availability could negatively impact our business.

PSCo’s coal generation portfolio is heavily dependent on coal supplies located in the Powder River Basin of Wyoming.  Approximately 50 percent of our annual coal requirement comes from this area. Coal generation comprises approximately 85 percent of our annual generation.  In the first half of 2005, we began experiencing disruptions in our coal deliveries from the Powder River Basin, which continued throughout the year and are expected to continue at least through part of 2006.  In response to these disruptions PSCo mitigated the impact of reduced coal deliveries, by modifying the dispatch of certain facilities to conserve coal inventories. In addition to the mitigation efforts, PSCo negotiated for the acquisition of additional, higher capacity rail cars and is working to upgrade certain coal handling facilities with completion anticipated in the first half of 2006.  Despite these efforts, coal inventories have declined to below target levels. While we have secured under contract approximately 99 percent of our anticipated 2006 coal requirements, we cannot predict with any certainty the likelihood of receiving the required coal.  This factor, combined with the currently low inventory levels, has led us to continue coal mitigation.  While we are planning to rebuild inventories during 2006, there is no guarantee that we will be able to do so.   The ultimate impact of coal availability cannot be fully assessed at this time, but could impact our future results. 

Rising energy prices could negatively impact our business.

A variety of market factors have contributed to higher natural gas prices.  The direct impact of these higher costs is generally mitigated for PSCo through recovery of such costs from customers through various fuel cost recovery mechanisms.  However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful.  In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on PSCo’s results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash flows of PSCo.  PSCo is unable to predict the future natural gas prices or  the ultimate impact of such prices on its results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. We expect that unusually mild winters and summers would have an adverse effect on our financial condition and results of operations.

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, that could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.  The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.  For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

Increasing costs associated with our defined benefit retirement plans, health care plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our earnings and funding requirements.  Based on our assumptions at Dec. 31, 2005 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain required funding levels for our pension plans, we do not expect to make required future contributions.  However, it is our practice to make voluntary contributions to maintain more prudent funding levels than minimally required.  These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.  Therefore, contributions could be required in the future.

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In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity. 

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot assure you that any of our current ratings or those of our affiliates will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Adverse developments at our affiliates could have an impact on out credit ratings.  Any future downgrade could increase the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events at Xcel Energy and its affiliates.  If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2005, the Xcel Energy holding company had approximately $5.9 billion of long-term debt and $1.6 million of short-term debt or current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.  Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2005, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $52.4 million and no known exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2005, was approximately $132.9 million.  Xcel Energy’s total exposure under these indemnities cannot be determined at this time.  Xcel Energy believes that the exposure is significantly less than the total amount of bonds outstanding.  If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek, within certain regulatory and other limitations and the limitations provided by corporate law, additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets.  This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such even were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We rely on Xcel Energy Services Inc., a subsidiary service company of Xcel Energy, for many administrative services.  If Xcel Energy were to experience severe financial difficulties, it could temporarily disrupt the provision of these services or require us to provide these services ourselves, at potentially greater cost.

We are a wholly owned subsidiary of Xcel Energy.  Xcel Energy can exercise, within certain regulatory and other limitations and the limitations provided by corporate law, substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

Our board of directors, as well as many of our executive officers, are officers of Xcel Energy.  Our board makes determinations with respect to the following:

•      our payment of dividends;

•      decisions on our financings and our capital raising activities;

•      mergers or other business combinations; and

•      our acquisition or disposition of assets.

We have historically paid quarterly dividends to Xcel Energy.  In 2005, 2004 and 2003 we paid $62.6 million, $243.9 million and $238.3 million of dividends to Xcel Energy, respectively.  Our board of directors could decide to increase dividends, within the limitations of our approved capital structure, financial covenants and credit rating objectives, to Xcel Energy to support its cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Any downgrade could also lead to higher long-term borrowing costs.

Item 1B — Unresolved SEC Staff Comments

None

Item 2 — Properties

Virtually all of the electric 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 2005 Net Dependable Capability (MW)
Steam:
Arapahoe —Denver, CO 2 Units	Coal	1950 – 1955	156
Cameo — Grand Junction, CO 2 Units	Coal	1957 – 1960	73
Cherokee — Denver, CO 4 Units	Coal	1957 – 1968	717
Comanche — Pueblo, CO 2 Units	Coal	1973 – 1975	660
Craig — Craig, CO 2 Units (a)	Coal	1979 – 1980	83
Hayden — Hayden, CO 2 Units (b)	Coal	1965 – 1976	237
Pawnee — Brush, CO	Coal	1981	505
Valmont — Boulder, CO	Coal	1964	186
Zuni — Denver, CO 2 Units	Natural Gas/Oil	1948 – 1954	107
Combustion Turbines:
Fort St. Vrain — Platteville, CO 4 Units	Natural Gas	1972 – 2001	690
Various Locations 6 Units	Natural Gas	Various	174
Hydro:
Various Locations 12 Units		Various	32
Cabin Creek — Georgetown, CO - Pumped Storage		1967	210
Wind:
Ponnequin — Weld County, CO		1999 – 2001	—
Diesel:
Diesel Generators: Cherokee — Denver, CO 2 Units		1967	6
Total			3,836

(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.

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2005:

Conductor Miles
345 KV	832
230 KV	10,892
138 KV	92
115 KV	4,844
Less than 115 KV	70,471

PSCo had 208 electric utility transmission and distribution substations at Dec. 31, 2005.

Natural gas utility mains at Dec. 31, 2005:

Miles
Transmission	2,300
Distribution	20,168

Item 3 — Legal Proceedings

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

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 asserted that trees falling into PSCo 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 were 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo.  The plaintiffs asserted damages in excess of $35 million.  In June 2005, PSCo reached a confidential settlement with all parties, as well as the United States Forest Service and the Denver Public Schools, settling claims in connection with the fire in Boulder County.  The financial impact of the settlement was not material to PSCo.

Other Matters

For more discussion of legal claims and environmental proceedings, see Note 12 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending and Recently Concluded Regulatory Proceedings under Item 1, incorporated by reference.

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

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

PART II

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

PSCo is a wholly owned subsidiary of Xcel Energy and there is no market for its common equity securities.

PSCo had dividend restrictions imposed by debt agreements and the SEC under the PUHCA limiting the amount of dividends PSCo can pay to Xcel Energy. These restrictions included, but may not have been limited to, the following:

•maintenance of a minimum equity ratio of 30 percent;

•payment of dividends only from retained earnings; and

•debt covenant restriction under the credit agreement for the debt to total capital ratio.

With the repeal of the PUHCA, restrictions on the ability of PSCo to declare dividends set out in that statute will no longer apply. However, dividends will be subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts.

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The dividends declared during 2005 and 2004 were as follows:

Quarter Ended (Thousands of Dollars)
March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
$	—	$	—	$	—	$	—
March 31, 2004		June 30, 2004		Sept. 30, 2004		Dec. 31, 2004
$	61,867	$	60,978	$	61,463	$	62,565

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, 2005.

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

Results Of Operations

PSCo’s net income was approximately $211.4 million for 2005, compared with approximately $218.0 million for 2004.

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

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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 Northern States Power Company, a Minnesota corporation, and SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC.  Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue.  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 purchased power, transmission, broker fees 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
2005
Electric utility revenue (excluding commodity trading)	$				2,486		$	17		$	—		$	2,503
Electric fuel and purchased power	(1,491					)	(16		)	—			(1,507		)
Commodity trading revenue	—						—			600			600
Commodity trading costs	—						—			(599		)	(599		)
Gross margin before operating expenses	$			995			$	1		$	1		$	997
Margin as a percentage of revenue	40.0					%	5.9		%	0.2%			32.1		%
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		%

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)	2005 vs 2004
Fuel cost recovery	$	189
Firm wholesale revenue	75
Estimated impact of weather	31
Purchased capacity cost adjustment	13
Sales mix	13
Service quality adjustment	10
Joint operating agreement revenue	7
Sales growth (excluding weather impact)	1
Other	19
Total base electric revenue increase	$	358

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Base Electric Margin

(Millions of Dollars)	2005 vs 2004
Estimated impact of weather	$	28
Firm wholesale	13
Increased capacity costs	(12)
Service quality adjustment	10
Pricing and other	9
Total base electric margin increase	$	48

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)	2005			2004
Natural gas utility revenue	$	1,329		$	1,074
Cost of natural gas sold and transported	(1,032		)	(785		)
Natural gas utility margin	$	297		$	289

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)	2005 vs 2004
Purchased gas adjustment clause recovery	$	241
Sales growth (excluding weather impact)	2
Estimated impact of weather	1
Transportation	5
Other	6
Total natural gas revenue increase	$	255

Natural gas revenue increased primarily due to higher gas costs, which are recoverd from customers.

Natural Gas Margin

(Millions of Dollars)	2005 vs 2004
Sales growth (excluding weather impact)	$	2
Estimated impact of weather	1
Transportation	3
Other	2
Total natural gas margin increase	$	8

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)	2005 vs 2004
Increase in bad debt	$	17
Higher customer service levels	9
Credits related to automated meter reading project	(10)
Higher employee benefit costs	8
Lower information technology costs	(6)
Higher plant outage related costs	2
Donations to energy assistance programs	2
Higher transportation fleet costs	2
Higher materials costs	2
Other	10
Total non-fuel operating expense increase	$	36

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Depreciation and amortization expense increased by approximately $15.0 million, or 6.7 percent, for 2005 compared with 2004, primarily due to plant additions and increased software amortization.

Taxes (other than income taxes) increased by approximately $4.8 million, or 5.5 percent, for 2005 compared with 2004, primarily due to higher property taxes.

Interest charges and financing costs decreased by approximately $9.8 million, or 6.5 percent, for 2005 compared with 2004, primarily due to the refinancing of long-term debt with lower coupon short-term debt and equity.

Interest and other income (expense) decreased by approximately $11.9 million primarily due to higher interest expense on COLI loans and lower interest income related to the finalization of prior-period IRS audits in 2004, partially offset by the gain on the sale of SO2 allowances.

Income tax expense decreased by approximately $2.6 million in 2005, compared with 2004.  The decrease was primarily due to lower income levels.  The effective tax rate was 24.9 percent for the period ended Dec. 31, 2005, compared with 25.0 percent for the same period in 2004. 

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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.  All financial and commodity related instruments, including derivatives, are subject to market risk.  These risks, as applicable to PSCo, are discussed in further detail below.

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 capacity, energy and energy-related products, and for various fuels used in the generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  PSCo’s risk-management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various commodity-marketing activities, including the purchase and sale of capacity, energy and energy related instruments. These marketing 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 activities within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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.

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.

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VaR is calculated on a consolidated basis. As of Dec. 31, 2005, the VaRs for the commodity trading operations were:

	Year ended		During 2005
(Millions of Dollars)	Dec. 31, 2005		Average		High		Low
Commodity trading (a)	$	2.06	$	1.44	$	4.43	$	0.26

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

VaR is calculated on a consolidated basis. As of Dec. 31, 2004, the VaRs for the commodity trading operations were:

	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.

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.  Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment.  Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments.  To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis, if required.  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, 2005 and 2004, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $1.9 million and $1.2 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 appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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Item 8 — Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Public Service Company of Colorado

We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, common stockholder’s equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2006

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)

	Year Ended Dec. 31
	2005			2004			2003
Operating revenues
Electric utility	$	2,504,028		$	2,194,628		$	2,117,790
Natural gas utility	1,329,034			1,073,989			883,052
Steam and other	33,501			27,825			23,271
Total operating revenues	3,866,563			3,296,442			3,024,113
Operating expenses
Electric fuel and purchased power	1,507,248			1,242,684			1,152,365
Cost of natural gas sold and transported	1,032,504			785,055			578,108
Cost of sales — steam and other	19,231			17,383			13,270
Operating and maintenance expenses	546,608			510,157			496,119
Depreciation and amortization	238,402			223,442			226,785
Taxes (other than income taxes)	91,438			86,671			83,386
Total operating expenses	3,435,431			2,865,392			2,550,033
Operating income	431,132			431,050			474,080
Interest and other income (expense), net (see Note 9)	(11,884		)	24			(7,020		)
Allowance for funds used during construction - equity	2,655			9,809			8,380
Interest charges and financing costs
Interest charges — including financing costs of $6,744, $7,353, and $7,822, respectively	144,835			157,447			160,914
Allowance for funds used during construction - debt	(4,589		)	(7,425		)	(8,990		)
Distributions on redeemable preferred securities of subsidiary trust	—			—			7,372
Total interest charges and financing costs	140,246			150,022			159,296
Income before income taxes	281,657			290,861			316,144
Income taxes	70,240			72,856			88,211
Net income	$	211,417		$	218,005		$	227,933

See Notes to Consolidated Financial Statements

30

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended Dec. 31
	2005			2004			2003
Operating activities
Net income	$	211,417		$	218,005		$	227,933
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	251,668			234,164			233,915
Deferred income taxes	111,455			79,493			86,748
Amortization of investment tax credits	(3,971		)	(4,000		)	(6,531		)
Allowance for equity funds used during construction	(2,655		)	(9,809		)	(8,380		)
Change in accounts receivable	(137,782		)	(107,652		)	(52,764		)
Change in accrued unbilled revenues	(61,760		)	(17,819		)	48,934
Change in inventories	(56,043		)	(31,781		)	6,703
Change in recoverable purchased natural gas and electric energy costs	(58,178		)	(27,068		)	(90,227		)
Change in prepayments and other current assets	17,773			(3,117		)	(23,843		)
Change in accounts payable	154,481			22,894			70,790
Change in other current liabilities	6,193			(5,222		)	48,166
Change in other noncurrent assets	(46,496		)	33,783			(18,299		)
Change in other noncurrent liabilities	(309		)	(44,812		)	12,438
Net cash provided by operating activities	385,793			337,059			535,583
Investing activities
Capital/construction expenditures	(424,292		)	(457,365		)	(433,572		)
Proceeds from disposition of property, plant and equipment	—			11,682			4,375
Allowance for equity funds used during construction	2,655			9,809			8,380
Other investments	6,520			(1,691		)	(21,215		)
Net cash used in investing activities	(415,117		)	(437,565		)	(442,032		)
Financing activities
Short-term borrowings — net	138,649			182,914			(89,715		)
Proceeds from issuance of long-term debt	129,500			—			815,996
Borrowings under 5-year unsecured credit facility	293,000			—			—
Repayments under 5-year unsecured credit facility	(293,000		)	—			—
Repayment of long-term debt and trust preferred securities, including reacquisition premiums	(375,354		)	(147,000		)	(627,883		)
Capital contribution from parent	202,029			184,123			145,496
Dividends paid to parent	(62,564		)	(243,906		)	(238,268		)
Net cash provided by (used in) financing activities	32,260			(23,869		)	5,626
Net increase (decrease) in cash and cash equivalents	2,936			(124,375		)	99,177
Cash and cash equivalents at beginning of year	726			125,101			25,924
Cash and cash equivalents at end of year	$	3,662		$	726		$	125,101
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	139,414		$	151,424		$	143,799
Cash paid for income taxes (net of refunds received)	$	(16,042	)	$	16,203		$	(17,589	)

See Notes to Consolidated Financial Statements

31

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

	Dec. 31, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	3,662		$	726
Accounts receivable – net of allowance for bad debts: $19,381 and $14,734, respectively	451,944			341,946
Accounts receivable from affiliates	47,746			19,961
Accrued unbilled revenues	234,614			172,854
Recoverable purchased natural gas and electric energy costs	230,393			172,215
Materials and supplies inventories – at average cost	42,602			44,897
Fuel inventory – at average cost	19,582			23,533
Natural gas inventory – at average cost	212,274			149,985
Derivative instruments valuation-at market	78,064			54,450
Prepayments and other	35,218			73,896
Total current assets	1,356,099			1,054,463
Property, plant and equipment, at cost:
Electric utility plant	6,275,046			6,123,791
Natural gas utility plant	1,793,240			1,691,895
Construction work in progress	209,721			200,118
Other	745,894			786,025
Total property, plant and equipment	9,023,901			8,801,829
Less accumulated depreciation	(2,854,757		)	(2,862,494		)
Net property, plant and equipment	6,169,144			5,939,335
Other assets:
Other investments	29,465			35,985
Regulatory assets	231,801			246,564
Derivative instruments valuation-at market	164,251			137,846
Other	35,191			38,413
Total other assets	460,708			458,808
Total assets	$	7,985,951		$	7,452,606
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	126,334		$	135,854
Short-term debt	335,604			186,300
Notes payable to affiliate	—			10,655
Accounts payable	578,722			415,652
Accounts payable to affiliates	26,388			35,865
Taxes accrued	81,638			72,446
Dividends payable to parent	—			62,565
Derivative instruments valuation-at market	66,463			60,586
Accrued interest	36,498			41,104
Other	71,206			87,294
Total current liabilities	1,322,853			1,108,321
Deferred credits and other liabilities:
Deferred income taxes	811,961			744,326
Deferred investment tax credits	62,984			66,955
Regulatory liabilities	492,335			475,136
Customers advances for construction	288,397			284,534
Minimum pension liability	86,099			62,669
Derivative instruments valuation-at market	170,849			157,130
Benefit obligations and other	122,511			87,022
Total deferred credits and other liabilities	2,035,136			1,877,772
Commitments and contingencies (see Note 12)
Long-term debt	1,945,973			2,179,961
Common stockholder’s equity:
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Premium on common stock	2,183,932			1,981,903
Retained earnings	604,163			392,746
Accumulated comprehensive loss	(106,106		)	(88,097		)
Total common stockholder’s equity	2,681,989			2,286,552
Total liabilities and equity	$	7,985,951		$	7,452,606

See Notes to Consolidated Financial Statements

32

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(Dollars in Thousands)

									Accumulated
									Other				Total
	Common Stock			Premium on		Retained			Comprehensive				Stockholder's
	Shares	Amount		Common Stock		Earnings			Income (loss)				Equity
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
Net income						211,417							211,417
Minimum pension liability adjustment, net of deferred tax of $(9,898) (see Note 8)									(16,644			)	(16,644			)
Net derivative instrument fair value changes during the period, net of tax of $(936)									(1,482			)	(1,482			)
Unrealized gain — marketable securities, net of tax of $71									117				117
Comprehensive income for 2005													193,408
Contribution of capital by parent				202,029									202,029
Balance at Dec. 31, 2005	100	$	—	$	2,183,932	$	604,163		$		(106,106	)	$	2,681,989

See Notes to Consolidated Financial Statements

33

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Thousands of Dollars)

	Dec. 31
	2005			2004
Long-Term Debt
First Mortgage Bonds, Series due:
Nov. 1, 2005, 6.375%	—			134,500
June 1, 2006, 7.125%	125,000			125,000
April 1, 2008, 5.625% (a)	—			18,000
Oct. 1, 2008, 4.375%	300,000			300,000
June 1, 2012, 5.5% (a)	—			50,000
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% (a)	—			61,500
Sept. 1, 2017, 4.375% (a)	129,500			—
Jan. 1, 2019, 5.1% (a)	48,750			48,750
Jan. 1, 2024, 7.25%	—			110,000
Unsecured Senior A Notes, due July 15, 2009, 6.875%	200,000			200,000
Secured Medium-Term Notes, due March 5, 2007, 7.11%	100,000			100,000
Capital lease obligations, 11.2% due in installments through 2028	47,581			48,935
Unamortized discount	(3,524		)	(5,870		)
Total	2,072,307			2,315,815
Less current maturities	126,334			135,854
Total long-term debt	$	1,945,973		$	2,179,961
Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2005 and 2004	$	—		$	—
Capital in excess of par value on common stock	2,183,932			1,981,903
Retained earnings	604,163			392,746
Accumulated other comprehensive loss	(106,106		)	(88,097		)
Total common stockholder’s equity	$	2,681,989		$	2,286,552

(a)Pollution control financing.

See Notes to Consolidated Financial Statements

34

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 was 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.

On Aug. 8, 2005, President Bush signed into law the Energy Act, significantly changing many federal energy statutes.  The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the FERC, the SEC and the DOE.  The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted.  The issues that the FERC has been required to consider associated with the repeal of the PUHCA include, but are not limited to, the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of holding companies and public utility companies previously governed by the SEC and the appropriate cost standard for the provision of non-power goods and services by service companies.  The FERC is in various stages of rulemaking on these and other issues.  Xcel Energy cannot predict the impact the new rulemakings will have on its operations or financial results, if any.

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 meters, 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 its revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

•PSCo generally recovers 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 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 Statement 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 contracts 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.

35

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 regulatory obligations are recorded 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 as incurred. Property, plant and equipment also includes costs associated with 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, 2005, 2004 and 2003 is 2.6 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 (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.  There is no legal obligation associated with these nuclear operations from the past.

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 if it is probable 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 emission-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 PSCo’s 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 may include final remediation costs.  Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs – Litigation accruals are recorded when it is probable that 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.

Investment tax credits are deferred and their benefits amortized 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.

36

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, asset retirement obligations, decommissioning, 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.   

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 are amortized over the remaining maturity periods of the related debt. PSCo’s deferred financing costs, net of amortization at Dec. 31, 2005 and 2004 are $13.5 million and $15.1 million, respectively.

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of write-offs and allowance for uncollectibles.  PSCo establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.

2. Short-Term Borrowings

Notes Payable and Commercial Paper — During 2005, PSCo resumed short-term borrowings in the commercial paper market.  Information regarding notes payable and commercial paper for the years ended Dec. 31, 2005 and 2004 is presented in the following table:

(Millions of Dollars, except interest rates)		2005			2004
Notes Payable to Banks	$	—		$	186.3
Commercial Paper		335.6			—
Total short-term debt	$	335.6		$	186.3
Weighted average interest rate at year end		4.48	%		3.40	%

Credit Facilities  — On Dec. 1, 2005, PSCo entered into an agreement with Wells Fargo Bank, N.A. to provide PSCo a committed five-month, $50 million seasonal revolving credit facility.  The interest rate is based on either Wells Fargo Bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by PSCo’s credit worthiness.  PSCo entered into this agreement to ensure adequate liquidity for rising natural gas prices during the winter months.  As of Dec. 31, 2005, PSCo had not borrowed against this facility.     

In addition, on Dec. 12, 2005, PSCo entered into a $25 million good-until-canceled uncommitted credit line with KBC Bank to provide additional short-term seasonal liquidity as a result of higher natural gas prices.  As of Dec. 31, 2005, PSCo had not utilized this credit line.

Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received

37

required state regulatory approvals.  The utility 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 utility 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, 2005.  As a consequence of the repeal of PUHCA and the recent amendments to the Federal Power Act, it may be necessary for PSCo to submit its existing money pool arrangement to FERC for its approval.  PSCo is presently evaluating the situation.

3.  Long-Term Debt

Effective Oct. 14, 2005, PSCo discharged in accordance with its terms its Indenture, dated as of December 1, 1939, as supplemented, (1939 Indenture).  As a result, PSCo’s Indenture, dated as of Oct. 1, 1993, as supplemented, (1993 Indenture) becomes the first lien on PSCo’s electric properties subject to certain permitted liens as provided in the 1993 Indenture.  PSCo’s outstanding first collateral trust bonds issued under the 1993 Indenture will, in accordance with their terms, no longer be secured by bonds issued under the 1939 Indenture and will become first mortgage bonds entitled to the benefit of the lien on PSCo’s electric properties under the 1993 Indenture and will be renamed “first mortgage bonds” to reflect this status.

Credit Facilities — At Dec. 31, 2005, PSCo had the following committed credit facilities available, in millions of dollars:

Facility			Available*	Term	Maturity
$	600	$	258.9	5 year	April 2010

* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  PSCo has the right to request an extension of the final maturity date by one year.  The maturity extension is subject to majority bank group approval.  The credit facility has one financial covenant requiring that PSCo’s debt to total capitalization ratio be less than or equal to 65 percent with which PSCo is in compliance.  The interest rate is based on either the agent bank’s prime rate or the applicable London Interbank Offered Rate (LIBOR), plus a borrowing margin as determined by PSCo’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch. 

As of Dec. 31, 2005, PSCo had no direct borrowings on this line of credit, however this credit facility was used to provide back-up support for PSCo commercial paper and letters of credit.  Also, $5.4 million of letters of credit were outstanding at Dec. 31, 2005, as discussed in Note 11 to the Consolidated Financial Statements, of which approximately $5.4 million were outstanding under the above credit facility and are included in the above table.

Maturities of long-term debt are:

(Millions of Dollars)
2006	$	126
2007	101
2008	301
2009	202
2010	2

4. Preferred Stock

PSCo has authorized the issuance of preferred stock.

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

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.

38

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, 2005:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress			Ownership %
Hayden Unit 1	$	84,357	$	43,579	$		635	75.5
Hayden Unit 2	80,034		45,637		1,006			37.4
Hayden Common Facilities	28,244		5,538		—			53.1
Craig Units 1 and 2	52,848		26,318		24			9.7
Craig Common Facilities, Units 1, 2 and 3	32,384		9,673		—			6.5 – 9.7
Comanche Unit 3	—		—		54,960			74.7
Transmission and other facilities, including substations	114,788		42,412		13			11.6 – 68.1
Total PSCo	$	392,655	$	173,157	$	56,638

PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  PSCo began major construction on a new jointly owned 750-MW, coal-fired unit in Pueblo, Colorado in January 2006.  Major construction on the new unit, Comanche 3, is expected to be completed in 2010.  PSCo is the operating agent under the joint ownership agreement. 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 following is a table reconciling such differences for the years ending Dec. 31:

	2005		2004		2003
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	2.3		3.4		2.9
Life insurance policies	(10.8	)	(9.4	)	(8.1	)
Tax credits recognized	(2.5	)	(2.1	)	(2.1	)
Regulatory differences —utility plant items	0.3		1.5		2.5
Resolution of income tax audits	0.5		(4.9	)	(2.9	)
Other — net	0.1		1.5		0.6
Effective income tax rate	24.9	%	25.0	%	27.9	%

Income taxes comprise the following expense (benefit) items for the years ending Dec. 31:

(Thousands of Dollars)	2005			2004			2003
Current federal tax expense (benefit)	$	(32,833	)	$	(2,866	)	$	15,643
Current state tax expense (benefit)	(4,411		)	2,229			(7,649		)
Current tax credits	—			(2,000		)	(2,498		)
Deferred federal tax expense	102,132			67,700			74,885
Deferred state tax expense	12,512			11,793			11,863
Deferred tax credits	(3,189		)	—			—
Deferred investment tax credits	(3,971		)	(4,000		)	(4,033		)
Total income tax expense	$	70,240		$	72,856		$	88,211

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

(Thousands of Dollars)	2005		2004
Deferred tax expense excluding items below	$	89,333	$	35,191
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	4,801		27,050
Tax expense (benefit) allocated to other comprehensive income and other	17,321		17,252
Deferred tax expense	$	111,455	$	79,493

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

(Thousands of Dollars)	2005		2004
Deferred tax liabilities:
Differences between book and tax basis of property	$	912,876	$	792,103
Regulatory assets	47,937		44,249
Deferred costs	84,685		46,006
Employee benefits	20,356		19,881
Other	12,143		4,002
Total deferred tax liabilities	$	1,077,997	$	906,241
Deferred tax assets:
Unbilled revenue	$	90,379	$	57,273
Other comprehensive income		64,538		53,776
Net operating loss carryforward	66,917		32,298
Deferred investment tax credits	23,680		25,250
Regulatory liabilities	13,479		12,852
Other	26,824		21,945
Total deferred tax assets	$	285,817	$	203,394
Net deferred tax liability	$	792,180	$	702,847

8. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.

Xcel Energy offers various benefit plans to its benefit employees, including those of PSCo. Approximately 56 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2005, PSCo had 2,165 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:

	2005		2004
Equity securities	65	%	69	%
Debt securities	20		19
Real estate	4		4
Cash	1		1
Nontraditional investments	10		7
	100	%	100	%

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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 12.0 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 achieved by pension assets in any year. Investment returns in 2005, 2004 and 2003 exceeded the assumed levels of 8.75 percent, 9.0 percent and 9.25 percent, respectively.  Xcel Energy continually reviews its pension assumptions.  In 2006, Xcel Energy will continue to use an investment return assumption of 8.75 percent.

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)	2005			2004
Accumulated Benefit Obligation at Dec. 31	$	2,642,177		$	2,575,317
Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,732,263		$	2,632,491
Service cost	60,461			58,150
Interest cost	160,985			165,361
Plan amendments	300			—
Actuarial loss	85,558			133,552
Settlements	—			(27,627		)
Benefit payments	(242,787		)	(229,664		)
Obligation at Dec. 31	$	2,796,780		$	2,732,263
Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,062,016		$	3,024,661
Actual return on plan assets	254,307			284,600
Employer contributions	20,000			10,046
Settlements	—			(27,627		)
Benefit payments	(242,787		)	(229,664		)
Fair value of plan assets at Dec. 31	$	3,093,536		$	3,062,016
Funded Status of Plans at Dec. 31
Net asset	$	296,756		$	329,753
Unrecognized prior service cost	214,702			244,437
Unrecognized loss	281,519			176,957
Xcel Energy net pension amounts recognized on balance sheet	$	792,977		$	751,147
PSCo intangible asset recorded — prior service costs	$	3,475		$	4,594
PSCo accrued benefit liability recorded	(2,315		)	(4,193		)
PSCo minimum pension liability recorded	(86,099		)	(62,669		)
PSCo accumulated other comprehensive income recorded – pretax	193,636			167,093
PSCo accumulated other comprehensive income recorded – net of tax	120,402			103,758
Measurement Date	Dec. 31, 2005			Dec. 31, 2004
Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	5.75		%	6.00		%
Expected average long-term increase in compensation level	3.50		%	3.50		%

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During 2002, one of PSCo’s pension plans became under funded, and at Dec. 31, 2005, had projected benefit obligations of $739.5 million, exceeding plan assets of $609.8 million. PSCo has recorded a minimum pension liability of $86.1 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 $120.4 million at Dec. 31, 2005, 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 $2.1 billion on Dec. 31, 2005.

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 2003 through 2005 for Xcel Energy’s pension plans and are not expected to require cash funding in 2006. PSCo elected to make voluntary contributions to its pension plan for bargaining employees of $9 million in 2004 and $14.7 million in 2005 and voluntarily contributed $3.4 million to the NCE non-bargaining plans in 2005.  PSCo expects to voluntarily contribute between $15 and $30 million during 2006 to its pension plan for bargaining employees.

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

(Thousands of Dollars)	2005			2004			2003
Service cost	$	60,461		$	58,150		$	67,449
Interest cost	160,985			165,361			170,731
Expected return on plan assets	(280,064		)	(302,958		)	(322,011		)
Curtailment gain	—			—			(17,363		)
Settlement gain	—			(926		)	(1,135		)
Amortization of transition asset	—			(7		)	(1,996		)
Amortization of prior service cost	30,035			30,009			28,230
Amortization of net (gain) loss	6,819			(15,207		)	(44,825		)
Net periodic pension credit under SFAS No. 87	$	(21,764	)	$	(65,578	)	$	(120,920	)
PSCo
Net periodic pension cost (credit)	$	14,252		$	7,141		$	(4,728	)
Significant Assumptions Used to Measure Costs
Discount rate	6.00		%	6.25		%	6.75		%
Expected average long-term increase in compensation level	3.50		%	3.50		%	4.00		%
Expected average long-term rate of return on assets	8.75		%	9.00		%	9.25		%

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 2006 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 also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s 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 $6.2 million in 2005, $7.2 million in 2004 and $4.7 million in 2003.

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. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement Benefits Other Than

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Pensions,” 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:

	2005		2004
Equity and equity mutual fund securities	61	%	54	%
Fixed income/debt securities	17		21
Cash equivalents	21		25
Nontraditional Investments	1		—
	100	%	100	%

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

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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)	2005			2004
Change in Benefit Obligation
Obligation at Jan. 1	$	929,125		$	775,230
Service cost	6,684			6,100
Interest cost	55,060			52,604
Plan amendments	—			(1,600		)
Plan participants’ contributions	12,008			9,532
Actuarial gain (loss)	(3,175		)	148,341
Benefit payments	(61,530		)	(61,082		)
Obligation at Dec. 31	$	938,172		$	929,125
Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	318,667		$	285,861
Actual return on plan assets	14,507			21,950
Plan participants’ contributions	12,008			9,532
Employer contributions	68,211			62,406
Benefit payments	(61,530		)	(61,082		)
Fair value of plan assets at Dec. 31	$	351,863		$	318,667
Funded Status at Dec. 31
Net obligation	$	586,309		$	610,458
Unrecognized transition obligation	(103,022		)	(117,600		)
Unrecognized prior service cost	15,736			17,914
Unrecognized loss	(364,745		)	(383,026		)
Accrued benefit liability recorded	$	134,278		$	127,746
PSCo accrued benefit liability recorded	$	39,503		$	44,620
Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	5.75		%	6.00		%

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.  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, 2005	$	62.9
1-percent decrease in APBO components at Dec. 31, 2005	(52.4		)
1-percent increase in service and interest components of the net periodic cost	5.0
1-percent decrease in service and interest components of the net periodic cost	(4.1		)

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 $75 million during 2006.

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

(Thousands of Dollars)	2005			2004			2003
Service cost	$	6,684		$	6,100			$	5,893
Interest cost	55,060			52,604			52,426
Expected return on plan assets	(25,700		)	(23,066		)	(22,185			)
Curtailment gain	—			—			(2,128			)
Settlement gain	—			—			(916			)
Amortization of transition obligation	14,578			14,578			15,426
Amortization of prior service credit	(2,178		)	(2,179		)	(1,533			)
Amortization of net loss	26,246			21,651			15,409
Net periodic postretirement benefit cost (credit) under SFAS No. 106	$       74,690			$   69,688			$    62,392
PSCo
Net periodic postretirement benefit cost recognized – SFAS No. 106	43,841			42,248			37,146
Additional cost recognized due to effects of regulation	3,891			3,891			3,883
Net cost recognized for financial reporting	$	47,732		$	46,139			$	41,029
Significant assumptions used to measure costs (income)
Discount rate	6.00		%	6.25		%	6.75			%
Expected average long-term rate of return on assets (before tax)	5.5%-8.5		%	5.5%-8.5		%	8.0%-9.0			%

Projected Benefit Payments

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
2006	$	218,093	$	63,966	$	4,777	$	59,189
2007	221,166		65,851		5,196		60,655
2008	228,196		67,635		5,582		62,053
2009	234,663		69,303		5,936		63,367
2010	239,730		70,851		6,248		64,603
2011-2015	1,216,821		366,454		34,719		331,735

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 consists of the following:

(Thousands of Dollars)	2005			2004			2003
Interest income	$	2,801		$	9,194		$	3,240
Other nonoperating income	3,597			1,322			1,970
(Loss) gain on disposal of assets	(9		)	6,583			1,765
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(18,273		)	(17,075		)	(13,995		)
Total interest and other income, net of nonoperating expenses	$	(11,884	)	$	24		$	(7,020	)

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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 capacity, energy and energy-related products, and for various fuels used in the generation and natural gas utility operation.  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, as allowed by regulation.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, 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 guidelines 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.

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.

Types of and Accounting for Derivative Instruments

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 qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, 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 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.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily 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 interest rate hedging transactions 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.

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Cash Flow Hedges

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, 2005, PSCo had various commodity-related contracts classified as cash flow hedges extending through 2009.  The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place.  Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale.

As of Dec. 31, 2005, PSCo had no amounts in Accumulated 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, 2005 and 2004, respectively.

Interest Rate Cash Flow Hedges — PSCo enters intointerest 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, 2005, PSCo had net gains of approximately $1.5 million in Accumulated 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, 2005 and 2004, 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, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive loss related to 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
After-tax net unrealized gains related to derivatives accounted for as hedges	11.9
After-tax net realized gains on derivative transactions reclassified into earnings	(13.4		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	14.2

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, 2005, 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

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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 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.

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, as amended.  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 the commodity trading contracts as of Dec. 31, 2005 and 2004 was $2.1 million and $(0.9) million, respectively.

The fair value of qualifying cash flow hedges at Dec. 31, 2005 and 2004 was $1.0 million and $(16.4) 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:

(Thousands of Dollars)	2005						2004
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term investments	$		12,877	$	12,877		$	28,908		$	28,908
Long-term debt, including current portion	$	2,072,307		$		2,187,802	$		2,315,815	$		2,464,979

The fair values 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, 2005 and 2004. 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.

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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, 2005, 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	$	0.50	$	(a	)	2006	(b	)	N/A

a)The total exposure of this indemnification cannot be determined.  PSCo believes the exposure to be significantly less than the total amount of the outstanding bonds.

b)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.

Letters of Credit

PSCo use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Dec. 31, 2005, there was $5.4 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

12. Commitments and Contingent Liabilities

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

In April 2004, Xcel Energy filed a lawsuit against the government in the U.S. District Court for the District of Minnesota to establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994.  After Xcel Energy had filed this suit, the IRS sent it two statutory notices of proposed deficiency of tax, penalty, and interest for taxable years 1995 through 1999.  Xcel Energy then timely filed two Tax Court petitions challenging those notices.  Xcel Energy anticipates that the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and that the two Tax Court petitions will be held in abeyance pending the outcome of the refund litigation.

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

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.  As discussed above, the litigation could require several years to reach final resolution.  Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.  Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

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Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce retained earnings by an estimated $361 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $428 million.  Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available.

COLI Dow Chemical Court Decision- On Jan. 23, 2006, the Sixth Circuit of the U.S. Court of Appeals issued an opinion in a federal income tax case involving the interest deductions for a COLI program at Dow Chemical Company.  The Sixth Circuit denied the tax deductions and reversed the decision of the trial court in this case.

Xcel Energy has analyzed the impact of the Dow decision on its pending COLI litigation and concluded there are significant factual differences between its case and the Dow case.  The court’s opinion in the Dow case outlined three indicators of potential economic benefits to be examined in a COLI case and noted the outcome of COLI cases is very fact determinative.  These indicators are:

•positive pre-deduction cash flows;

•mortality gains; and

•the buildup of cash values.

In a split decision, the Sixth Circuit found that the Dow COLI plans possessed none of these indicators of economic substance.  However, in Xcel Energy’s COLI case, the plans were projected to have sizeable pre-deduction cash flows, based upon the relevant assumptions when purchased.  Moreover, the plans presented the opportunity for mortality gains that were not eliminated either retroactively or prospectively.  Xcel Energy’s COLI plans had no provision for giving back any mortality gains that it might realize. In addition, Xcel Energy’s plans had large cash value increases that were not encumbered by loans during the first seven years of the policies.  Consequently, Xcel Energy believes that the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strong merits.

Leases— PSCo leases a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2029.  The assets and liabilities acquired under capital leases are recorded at the lower of fair-market value or the present value of future lease payments and are depreciated over their actual contract term in accordance with practices allowed by regulators.  Depreciation of assets under capital leases is included in depreciation expense for 2005 and 2004.

Following is a summary of property held under capital leases:

(Millions of Dollars)	2005			2004
Storage, leaseholds and rights	$	40.5		$	40.5
Gas pipeline	20.7			20.7
	61.2			61.2
Less: Accumulated depreciation	(13.6		)	(12.3		)
Total property held under capital leases	$	47.6		$	48.9

The remainder of the leases, primarily for office space, railcars, trucks, cars and power-operated equipment are accounted for as operating leases.  Rental expense under operating lease obligations was approximately $19.6 million, $17.6 million and $22.4 million for 2005, 2004 and 2003, respectively.

Future commitments under operating leases are:

2006		2007		2008		2009		2010		Thereafter
(Millions of Dollars)
$	14.3	$	10.7	$	10.2	$	9.9	$	9.5	$	43.9

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Future commitments under PSCo’s two capital leases are:

	(Millions of Dollars)
2006	$	7
2007	6
2008	6
2009	6
2010	6
Thereafter	68
Total minimum obligation	$	99
Less: Amount representing interest	(51		)
Present value of minimum obligation	$	48

Capital Commitments — The estimated cost, as of Dec. 31, 2005, of the capital expenditure programs and other capital requirements of PSCo is approximately $536 million in 2006, $684 million in 2007 and $604 million in 2008.

PSCo’s capital expenditure forecast includes the 750-MW Comanche 3 coal-fired plant in Colorado.  Comanche 3 is expected to cost approximately $1.35 billion, with major construction starting in 2006 and finishing in 2010.  The Colorado commission has approved sharing one-third ownership of this plant with other parties.  Consequently, PSCo’s capital expenditure forecast includes $1 billion, approximately two-thirds of the total cost.

The capital expenditure programs of PSCo are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting PSCo’s long-term energy needs. In addition, PSCo’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

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 2006 and 2025. In addition, PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.

The estimated minimum purchase obligation for PSCo under these contracts as of Dec. 31, 2005, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
(Millions of Dollars)
$	342	$	1,157	$	400

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 2027. 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 rate adjustment mechanisms.

At Dec. 31, 2005, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, are as follows (Thousands of Dollars):

2006	$		408,152
2007	421,239
2008	418,942
2009	389,760
2010	367,573
2011 and thereafter	1,464,577
Total	$	3,470,243

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Environmental Contingencies

PSCo has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the rate regulatory process.   To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense for such unrecoverable amounts in its Consolidated Financial Statements.

Site Remediation — PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo and some other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including the following categories of sites:

•the site of a former federal uranium enrichment facility,

•site of a former manufactured gas plant (MGP) operated by PSCo or its predecessors and

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

PSCo records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received.  The estimated remediation cost may vary materially.

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

Estimates are revised as facts become known..  At Dec. 31, 2005, the liability for the cost of remediating sites was estimated to be $1.2 million, of which $0.7 million was considered to be a current liability.  Some of the cost of remediation may be recovered from:

•insurance coverage;

•other parties that have contributed to the contamination; and

•customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for PSCo’s future costs for these sites.

Federal Uranium Enrichment Facility

Approximately $0.5 million of the long-term liability for PSCo relates to a DOE assessment for decommissioning a federal uranium enrichment facility. This environmental liability does not include accruals recorded and collected from customers in rates for future nuclear fuel disposal.

Manufactured Gas Plant Site

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property.  An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River.  On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work.   PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring.  In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of clean-up costs at the Fort Collins MGP plant spent through March 2005, which amounted to $6.2 million to be amortized over four years.  PSCo reached a settlement agreement with the parties in the case.  The CPUC approved the settlement agreement on Jan. 19, 2006, and the final order became effective on Feb. 3, 2006,

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with rates effective Feb. 6, 2006.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site.  PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River.  On December 14, 2005 the court denied Schrader’s request to dismiss the PSCo suit.  On Jan. 3, 2006 Schrader filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the CERCLA and under the Resource Conservation and Recovery Act (RCRA).  Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA.  PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself.

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.  PSCo has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations elsewhere in Note 12.  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.

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.  On Dec. 31, 2005, PSCo’s leases of the Leyden properties were terminated and the city of Arvada took custody of the facility.  PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2005, PSCo has incurred approximately $5.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs.  PSCo has accrued an additional $0.2 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..  In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of Leyden costs totaling $4.8 million to be amortized over four years.  PSCo has reached a settlement agreement with the parties in the case.  The CPUC approved the settlement agreement on Jan. 19, 2006, and the final order became effective on Feb. 3, 2006.  PSCo believes that the additional $0.9 million of costs incurred may be recovered in a future case.

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 CERCLA.  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 RCRA program.  On Nov. 24, 2004, the EPA sent a letter to the COGCC requesting that the COGCC contact PSCo and request certain information concerning the closure.  To date no formal request has been received by PSCo.

On August 17, 2005, the EPA requested information from PSCo regarding the compliance status of the Leyden facility under the federal Clean Air Act (CAA).  On Sept. 19, 2005, PSCo responded to the requests for information.  PSCo believes the Leyden facility is in compliance with the CAA and other applicable state and federal environmental laws.  PSCo cannot predict the ultimate outcome of this inquiry, however, any consequence is not expected to have a material impact.

Other Environmental Requirements

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.  Some PSCo generating facilities will be subject to BART requirements.

States must develop their implementation plans by December 2007. States will identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities.  Colorado is the first state in Xcel Energy’s region to earnestly begin its BART rule development as the first step toward the December 2007 deadline.  Xcel Energy is actively involved in the stakeholder process in Colorado and will also be involved as other states begin their process.  Due to the uncertainties of the many decisions involved in this process, PSCo is not able to estimate the cost impact to the company at this time.

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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 a few 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, including unresolved third party legal challenges to the federal rule.  Based on the limited information available, total capital and operating and maintenance costs to PSCo are estimated at approximately $0.5 million over the next five to 10 years. Actual costs may be higher or lower depending on the final resolution of legal challenges to the rule, as well as pending state and federal decisions regarding interpretation of specific rule requirements.

Notice of Violation — On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA 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 CAA 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 CAA, the EPA met with PSCo in September 2002 to discuss the NOV.

On March 10, 2005, the Rocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo of its intent to sue PSCo for alleged violations of the CAA at the Comanche plant.  The notice of intent to sue alleges PSCo has violated the CAA’s Prevention of Significant Deterioration regulations based on allegations that maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process.  The allegations are the same as those presented in the NOV.  On June 9, 2005, Citizens for Clean Air and Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom provided notice of intent to sue PSCo for alleged violations of the CAA at the Comanche Plant.  The allegations in the notice of intent to sue by CCAP and Ms. Glustrom are substantially identical to those of RMELC.  PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which may be filed.  Currently, PSCo is not able to estimate any potential loss.

Asset Retirement Obligations

PSCo adopted Statement of Financial Accounting Standard SFAS No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143) effective Jan. 1, 2003.  PSCo records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47— “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to SFAS No. 143.  The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event.  FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. PSCo implemented FIN No. 47 as of Dec. 31, 2005.  Included in these financial statements is the recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis.

Recorded Asset Retirement Obligations (ARO) — Asset retirement obligations have been recorded for steam production, electric transmission and distribution systems and natural gas distribution systems.  The steam production obligation includes asbestos and ash-containment facilities.  The asbestos recognition associated with the steam production includes certain plants at PSCo.  Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  Asset retirement obligations also have been recorded  for PSCo steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.

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PSCo recognized an ARO for the retirement costs of gas mains.  In addition, an ARO was recognized for the removal of electric, transmission and distribution equipment.  The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year.  Therefore, the obligation was measured at Dec. 31, 2005.  The asset retirement cost was set to this recognized obligation and no cumulative effect adjustment was shown.

A reconciliation of the beginning and ending aggregate carrying amount of PSCo’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2005:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2005		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates		Ending Balance Dec. 31, 2005
Electric Utility Plant:
Steam production asbestos	$	—	$	1,462	$	—	$	7,637	$	—	$	9,099
Steam production ash containment	—		882		—		2,838		—		3,720
Electric transmission and distribution	—		700		—		—		—		700
Gas Utility Plant:
Gas transmission and distribution	—		28,449		—		—		—		28,449
Total liability	$	—	$	31,493			$	10,475	$	—	$	41,968

Cumulative Effect of FIN No. 47 — In March 2005, the FASB issued FIN No. 47.  The interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No. 143.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.  If PSCo had implemented FIN No. 47 at Jan. 1, 2004, the liability for asset retirement obligations would have increased by $11.4 million.  The same liability at Dec. 31, 2004 would have increased by $12.1 million.  A summary of the accounting for the initial adoption of FIN No. 47, as of Dec. 31, 2005 is as follows:

(Thousands of Dollars)	Plant Assets			Regulatory Assets		Long-Term Liabilities
Reflect retirement obligation when liability incurred	$	31,493		$	—	$	31,493
Record accretion of liability to adoption date	—			10,475		10,475
Record depreciation of plant to adoption date	(1,314		)	1,314		—
Net impact of FASB Interpretation No. 47	$	30,179		$	11,789	$	41,968

Indeterminate Asset Retirement Obligations — PSCo has underground gas storage facilities that have special closure requirements for which the final removal date cannot be determined.

Removal Costs - PSCo accrues an obligation for plant removal costs for generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO 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.  Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2005 and 2004 are $377 million and $383 million, respectively.

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 a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.

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

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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, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have filed a notice of appeal.

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 also is considerable debate regarding public policy for the approach that the United States 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 United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies.  Xcel Energy is closely monitoring the issue from both scientific and policy perspectives.  While it is not possible to know the eventual outcome, Xcel Energy 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 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.  In certain jurisdictions, the evaluation process for future generating resources incorporates the risk of future carbon limits through the use of a carbon cost adder or externality costs.  Xcel Energy also is involved in other projects to improve available methods for managing carbon.

Payne et al. vs. PSCo et al. - In late October 2003, there was a wildfire in Boulder County, Colorado.  There was no loss of life, but there was property damage associated with this fire. On Oct. 28, 2005, an action against PSCo relating to this fire was filed in Boulder County District Court. There are 28 plaintiffs, including individuals, the City of Jamestown and one private corporation, and three co-defendants, including PSCo. Plaintiffs have asserted that a tree falling into PSCo distribution lines may have caused the fire. This lawsuit is in its early stages and PSCo intends to vigorously defend itself against the claims asserted in this lawsuit . This lawsuit is not expected to have a material financial impact and PSCo believes that its insurance coverage will cover any liability in this matter.

Comanche 3 Permit Litigation - On Aug. 4, 2005, CCAP and Clean Energy Action filed suit against the Air Pollution Control Division, Colorado Department of Public Health and Environment in state district court in Pueblo, Colo. The suit alleges the issuance of environmental permits for the proposed Comanche 3 generating station by the Department violates the Colorado Air Pollution Prevention and Control Act. The plaintiffs have sought judicial review of the issuance of the permits. The plaintiffs have not sought a stay of the permits or an injunction on construction pending judicial review. On Aug. 19, 2005, the Colorado attorney general, on behalf of the Department, filed an answer in the suit. On the same date, PSCo filed a motion to intervene and an answer in the suit.  On Nov. 20, 2005, the Division submitted the formal record, which was entered by the Court. The plaintiff’s brief was filed on Feb. 2, 2006, and the government and PSCo will have 60 days to respond.

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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.  If changes in the utility industry or the business of PSCo no longer allow for the application of SFAS No. 71 under GAAP, PSCO would be required to recognize the write-off of regulatory assets and liabilities in its statement of income.  The components of unamortized regulatory assets and liabilities on the balance sheets of PSCo are:

(Thousands of Dollars)	See Note	Remaining Amortization Period	2005		2004
Regulatory Assets:
Contract valuation adjustments (b)	10	Term of related contract	$	58,214	$			83,981
Employees’ postretirement benefits other than pension	8	Seven years	27,234		31,125
AFDC recorded in plant (a)		Plant lives	40,168		42,236
Conservation programs (a)		Various	59,114		44,923
Losses on reacquired debt	1	Term of related debt	26,228		22,495
Nuclear decommissioning costs (c)			—		7,884
Plant asset recovery (Pawnee II and Metro Ash)		Eighteen months	7,355		12,258
Non-nuclear asset retirement obligations		Plant lives	11,789		—
Other		Various	1,699		1,662
Total regulatory assets			$	231,801	$		246,564
Regulatory Liabilities:
Plant removals costs	12		$	377,343	$		383,035
Investment tax credit deferrals			38,134		40,663
Contract valuation adjustments (b)	10		46,827		26,670
Deferred income tax adjustments			30,031		24,768
Total regulatory liabilities			$	492,335	$	475,136

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

b)Includes the fair value of certain long-term contracts used to meet native energy requirements.

c)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.

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The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which are separately determined for each segment.

(Thousands of Dollars)	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
2005
Operating revenues from external customers	$	2,504,028	$	1,329,034	$	33,501		$	—		$	3,866,563
Intersegment revenues	263		97		—			(360		)	—
Total revenues	$	2,504,291	$	1,329,131	$	33,501		$	(360	)	$	3,866,563
Depreciation and amortization	$	179,774	$	52,009	$	6,619		$	—		$	238,402
Financing costs, mainly interest expense	108,824		30,150		2,241			(969		)	140,246
Income tax expense (benefit)	89,579		23,112		(42,451		)	—			70,240
Segment net income	$	153,436	$	43,458	$	14,523		$	—		$	211,417
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

15. Related Party Transactions

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.

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals.  See Note 2 for further discussion of this borrowing arrangement.

Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provides construction services to PSCo, for which it was paid $3.3 million in 2005, $12.9 million in 2004 and $30.1 million in 2003.  UE was sold in April 2005.

Cheyenne Light, Fuel and Power (Cheyenne), a former 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)	2005		2004		2003
Operating revenues:
Electric utility	$	2,378	$	48,666	$	55,855
Natural gas utility	—		—		150
Operating expenses:
Other operations — paid to Xcel Energy Services Inc	256,290		298,124		259,788
Interest expense	725		886		1,103

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

	2005					2004
(Thousands of Dollars)	Accounts Receivable			Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	22,356		$	162	$	12,197	$	72
NSP-Wisconsin	—			2,281		54		—
SPS	86			—		334		1
Other subsidiaries of Xcel Energy Inc.	25,304			23,945		7,376		35,792
	$		47,746	$	26,388	$	19,961	$	35,865

1480 Welton, Inc., a PSCo subsidiary, had notes payable outstanding  as of Dec. 31, 2005 and 2004 to Xcel Energy, in the amount of $0 and $10.7 million, respectively.

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
Revenue	$	1,039,277	$	783,208	$	782,723	$	1,261,355
Operating income	125,713		95,931		99,273		110,215
Net income	65,607		47,188		45,678		52,944

	Quarter Ended
(Thousands of Dollars)	March 31, 2004		June 30, 2004		Sept. 30, 2004		Dec. 31, 2004 (a)
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

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 2004 and 2005, and through the date of this report, there were no disagreements with the independent public accountants for PSCo on accounting principles or practices, financial statement 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 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 its 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 materially affect, PSCo’s internal control over financial reporting.

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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 2006 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, 2005, 2004 and 2003.

Consolidated Statements of Income — For the three years ended Dec. 31, 2005, 2004 and 2003.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2005, 2004 and 2003.

Consolidated Balance Sheets — As of Dec. 31, 2005 and 2004.

2.Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2005, 2004 and 2003.

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 Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.02*	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, 2002	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

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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 10-K, Mar. 15, 2004 (001-03034)	4.100
				Aug. 1, 2005	PSCo 8-K, Aug. 18, 2005 (001-03280)	4.02

4.03*	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).
4.04*	Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*	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).
4.06*	$500,000,000 Credit Agreement among Public Service Company of Colorado, as Borrower, the several lenders from time to time parties hereto, Keybank National Association and USB Loan Finance LLC, as documentation agents, The Bank of New York and Wells Fargo Bank, National Association, as syndication agents and JPMorgan Chase Bank, N.A., as administrative agent dated as of April 21, 2005 (Exhibit 4.02 to Form 10-Q (file no. 001-03034) dated March 31, 2005).
4.07	$50,000,000.00 Revolving Line of Credit Note between Public Service Company of Colorado and Wells Fargo Bank, National Association, as of December 1, 2005.
4.08	Amendment to the Credit Agreement dated April 21, 2005 between Public Service Company of Colorado and various lenders dated Oct. 31, 2005.
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to 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 Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).

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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 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, 2004 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 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 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 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 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) for the year ended Dec. 31, 2004).
10.26*+	Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.01 to Xcel Energy Form 10-Q (file no. 001-03034) dated Sept. 30, 2005.
10.27*+	Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.28*+	Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.29*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.30*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.31*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.32*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.33*+	Xcel Energy Omnibus 2005 Incentive Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.34*+	Xcel Energy Executive Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.35*+	Xcel Energy Amended Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).
10.36*+	Xcel Energy Supplemental Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13, 2005).
10.37+	Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2006
10.38+	Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy
10.39*	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 (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)).
10.40*	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 (file no. 001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)).
10.41*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.42*	Settlement Agreement among Public Service Co. of Colorado and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
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.

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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.

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SCHEDULE II

PUBLIC SERVICE COMPANY OF COLORADO

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2005, 2004 and 2003

(Thousands of Dollars)

				Additions
	Balance at beginning of period			Charged to costs & expenses		Charged to other accounts (1)		Deductions from reserves (2)		Balance at end of period
Reserve deducted from related assets:
Provision for uncollectible accounts:
2005	$		14,734	$	24,214	$	6,216	$	25,783	$	19,381
2004	$		12,852	$	12,823	$	4,742	$	15,683	$	14,734
2003	$	13,685		$	10,447	$	8,914	$	20,194	$	12,852

1) Recovery of amounts previously written off.

2) Principally uncollectible accounts written off or transferred.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

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)

February 24, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated above.

/s/ PATRICIA K. VINCENT	/s/ GARY R. JOHNSON
Patricia K. Vincent	Gary R. Johnson
President, Chief Executive Officer 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	Chairman and Director
(Principal Accounting Officer)
/s/ BENJAMIN G.S. FOWKE III	/s/ PAUL J. BONAVIA
Benjamin G.S. Fowke III	Paul J. Bonavia
Vice President, Chief Financial Officer and Director	Vice President and Director
(Principal Financial Officer)
/s/ CYNTHIA L. LESHER
Cynthia L. Lesher
Vice President and Director

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SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES 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.

66