** **

**UNITED STATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**(Mark One)**

| **ý** | ** ** | **ANNUAL REPORT PURSUANT TO  SECTION 13 OR 15(d) OF**                                                                                                                                                                                                                                                                                |
|------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|       |       | **THE SECURITIES EXCHANGE ACT OF  1934**                                                                                                                                                                                                                                                                                             |
|       |       |                                                                                                                                                                                                                                                                                                                                 |
|       |       | **For the fiscal year ended December 31, 2004**                                                                                                                                                                                                                                                                                      |
|       |       |                                                                                                                                                                                                                                                                                                                                 |
| **OR**     |
|       |       |                                                                                                                                                                                                                                                                                                                                 |
| **o**      | ** ** | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF**                                                                                                                                                                                                                                                                            |
|       |       | **THE SECURITIES EXCHANGE ACT OF  1934**                                                                                                                                                                                                                                                                                             |
|       |       |                                                                                                                                                                                                                                                                                                                                 |
|       |       | **For the transition period from                        to                        ** |

 

**COMMISSION FILE NUMBER 001-03280**

 

**PUBLICSERVICE  COMPANY OF COLORADO**

(Exact name of registrant as specified in itscharter)

 
| **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, includingarea code)

 

Securities registered pursuant to Section12(b) of the Act:**  None**

 

Securities registered pursuant to Section12(g) of the Act:**  None**

 

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

 

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

 

Indicate bycheck mark whether the registrant is an accelerated filer (as defined in Rule12b-2 of the Act).  Yes o   No ý

 

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

 

**DOCUMENTS INCORPORATED BY REFERENCE: XcelEnergy Inc.’s 2005 Proxy Statement**

 

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

 

 

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**INDEX**

 
| ** **                                                                                                 | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|
| **PART I**                                                                                                 |       |
| Item 1 —  Business                                                                                    |       |
| DEFINITIONS                                                                                                |       |
| COMPANY  OVERVIEW                                                                                          |       |
| ELECTRIC UTILITY OPERATIONS                                                                                |       |
| Summary  of Recent Regulatory Developments                                                                 |       |
| General  Electric Utility Pending Regulatory Matters                                                       |       |
| Ratemaking  Principles                                                                                     |       |
| Capacity  and Demand                                                                                       |       |
| Energy Sources                                                                                             |       |
| Fuel  Supply and Costs                                                                                     |       |
| Trading  Operations                                                                                        |       |
| Electric Operating  Statistics                                                                             |       |
| NATURAL GAS UTILITY  OPERATIONS                                                                            |       |
| Summary of  Recent Regulatory Developments                                                                 |       |
| Ratemaking  Principles                                                                                     |       |
| Capability  and Demand                                                                                     |       |
| Natural Gas Supply and  Costs                                                                              |       |
| Natural Gas Operating  Statistics                                                                          |       |
| ENVIRONMENTAL  MATTERS                                                                                     |       |
| EMPLOYEES                                                                                                  |       |
| Item 2 —  Properties                                                                                  |       |
| Item 3 — Legal Proceedings                                                                            |       |
| Item  4 — Submission of Matters to a Vote of Security Holders                                         |       |
|                                                                                                       |       |
| **PART II**                                                                                                |       |
| Item  5 — Market for Registrant’s Common Equity and Related Stockholder Matters                  |       |
| Item 6 — Selected  Financial Data                                                                     |       |
| Item  7 — Management’s Discussion and Analysis of Financial Condition and Results  of Operations |       |
| Item  7A — Quantitative and Qualitative Disclosures About Market Risk                                 |       |
| Item  8 — Financial Statements and Supplementary Data                                                 |       |
| Item  9 — Changes in and Disagreements with Accountants on Accounting and Financial  Disclosure       |       |
| Item 9A — Controls  and Procedures                                                                    |       |
| Item 9B — Other  Information                                                                          |       |
|                                                                                                       |       |
| **PART  III**                                                                                              |       |
| Item  10 — Directors and Executive Officers of the Registrant                                         |       |
| Item 11 — Executive  Compensation                                                                     |       |
| Item  12 — Security Ownership of Certain Beneficial Owners and Management                             |       |
| Item  13 — Certain Relationships and Related Transactions                                             |       |
| Item  14 — Principal Accounting Fees and Services                                                     |       |
|                                                                                                       |       |
| **PART IV**                                                                                                |       |
| Item  15 — Exhibits, Financial Statement Schedules                                                    |       |
|                                                                                                       |       |
| **SIGNATURES**                                                                                             |       |
|                                                                                                       |       |

 

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

 

2

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**PART I**

 

**Item l**— **Business**

 

# **DEFINITION**OFABBREVIATIONS 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 allowing PSCo to                                                                                                                                                                                                                                                                   |

 

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|                                |   | equally  share between electric customers and shareholders of certain fuel and  purchased energy costs and expired Dec. 31, 2002. The collection of prudently  incurred 2002 ICA costs is being amortized over the period June 1, 2002  through March 31, 2005.                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|-------------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| IAC                                 |   | Interim  adjustment clause.A retail adjustment clause allowing PSCo to recover  prudently incurred fuel and energy costs not included in electric base rates.This  clause expired Dec. 31, 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| PCCA                                |   | Purchased  capacity cost adjustment. Allows PSCo to recover from customers purchased  capacity payments to power suppliers under specifically identified power  purchase agreements that are not included in the determination of PSCo’s base  electric rates or other recovery mechanisms. This clause will expire on Dec.  31, 2006.                                                                                                                                                                                                                                                                                                                                                                              |
| QSP                                 |   | Provides for bill credits  to Colorado retail customers if PSCo does not achieve certain operational  performance targets.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| SCA                                 |   | Steam cost  adjustment. Allows PSCo to recover the difference between its actual cost of  fuel and the amount of these costs recovered under its base steam service  rates. The SCA is revised annually to coincide with changes in fuel costs.                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|                                |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| ***Other Terms and Abbreviations*** |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| AFDC                                |   | Allowance  for funds used during construction. Defined in regulatory accounts as a  non-cash accounting convention that represents the estimated composite  interest costs of debt and a return on equity funds used to finance  construction. The allowance is capitalized in property accounts and included  in income.                                                                                                                                                                                                                                                                                                                                                                                                |
| ALJ                                 |   | Administrative  law judge. A judge presiding over regulatory proceedings.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| ARO                                 |   | Asset  Retirement Obligation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| COLI                                |   | Corporate-owned  life insurance.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Deferred  energy costs              |   | The amount  of fuel costs applicable to service rendered in one accounting period that  will not be reflected in billings to customers until a subsequent accounting  period.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| Derivative  instrument              |   | A financial  instrument or other contract with all three of the following characteristics:  

•     An underlying and a  notional amount or payment provision or both,

•     Requires no initial  investment or an initial net investment that is smaller than would be  required for other types of contracts that would be expected to have a  similar response to changes in market factors, and 

•     Terms require or permit a  net settlement, can be readily settled net by means outside the contract or provides  for delivery of an asset that puts the recipient in a position not  substantially different from net settlement |
| Distribution                        |   | The system  of lines, transformers, switches and mains that connect electric and natural  gas transmission systems to customers.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| ERISA                               |   | Employee  Retirement Income Security Act                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| FASB                                |   | Financial  Accounting Standards Board                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| FTRs                                |   | Financial  Transmission Rights                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| GAAP                                |   | Generally  accepted accounting principles                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| Generation                          |   | The process  of transforming other forms of energy, such as nuclear or fossil fuels, into  electricity. Also, the amount of electric energy produced, expressed in  megawatts (capacity) or megawatt hours (energy).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| C20                                 |   | Derivatives  Implementation Group of FASB Implementation Issue No. C20. Clarified the  terms clearly and closely related to normal purchases and sales contracts, as  included in SFAS No. 133, as amended.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| JOA                                 |   | Joint  operating agreement among the Utility Subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |

 

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

 

5

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

## ** **

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## ** **

## **COMPANY OVERVIEW**

## ** **

PSCo was incorporated in1924 under the laws of Colorado. PSCo is an operating utility engaged primarilyin the generation, purchase, transmission, distribution and sale ofelectricity.  PSCo also purchases,transports, distributes and sells natural gas to retail customers andtransports customer-owned natural gas. PSCo serves approximately 1.3 million electric customers and approximately1.2 million natural gas customers in Colorado.

 

PSCo owns the followingdirect subsidiaries: 1480 Welton, Inc., which owns certain real estateinterests for PSCo; PSRI, which owns and manages permanent life insurancepolicies on certain current and former employees; and Green and Clear LakesCompany, which owns water rights. PSCo also holds a controlling interest inseveral other relatively small ditch and water companies whose capitalrequirements are not significant. PS Colorado Credit Corp., a finance companythat was owned by PSCo and financed certain of PSCo’s current assets, wasdissolved in 2002. PSCo owned PSCo Capital Trust I, a special purpose financingtrust, for which a certificate of cancellation was filed for dissolution onDec. 29, 2003.  PSCo is a wholly ownedsubsidiary of Xcel Energy.

 

Xcel Energy wasincorporated under the laws of Minnesota in 1909 and is a registered holdingcompany under the PUHCA. Xcel Energy is subject to the regulatory oversight ofthe SEC under PUHCA. The rules and regulations under PUHCA impose a number ofrestrictions on the operations of registered holding company systems. Theserestrictions include, subject to certain exceptions, a requirement that the SECapprove securities issuances, payments of dividends out of capital or unearnedsurplus, sales and acquisitions of utility assets or of securities of utilitycompanies and acquisitions of other businesses. PUHCA also generally limits theoperations of a registered holding company to a single integrated publicutility system, plus additional energy-related businesses. PUHCA rules requirethat transactions between affiliated companies in a registered holding companysystem be performed at cost, with limited exceptions.

 

In 2004, Xcel Energycontinuing operations included the activity of four wholly owned utilitysubsidiaries, including PSCo, that serve electric and natural gas customers in10 states. The other utility subsidiaries are NSP-Minnesota, NSP-Wisconsin andSPS. These utilities serve customers in portions of Colorado, Kansas, Michigan,Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas andWisconsin.

 

**ELECTRICUTILITY OPERATIONS**

 

**Overview**

 

***Utility Industry Growth***— After adecade of cost cutting and efficiency gains in anticipation of industryrestructuring and competition, areas of growth for the utility industry arelimited.  The most significant areas forearnings growth include increasing regulated rates, increased investment inrate base, diversification, acquisition or modification of rate structures toimplement performance-based rates.  PSCointends to focus on growing through investments in electric and natural gasrate base to meet growing customer demands and to maintain or increase reliabilityand quality of service to customers and rate case filings with state andfederal regulators to increase rates congruent with increasing costs ofoperations 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 pasthad been significant as utilities combined to capture economies of scale orestablish a strategic niche in preparing for the future, although such activityslowed substantially after 2001.  All investor-ownedutilities were required to provide nondiscriminatory access to the use of theirtransmission systems in 1996.  Beginningin the late 1990s, many states began studying or implementing some form ofretail electric utility competition.  Asa result of the failure of the California power market structure andnonregulated investments of many utilities, as well as other factors, mostutility retail market restructuring has ceased. No significant activity has occurred or is expected to occur in any ofthe retail jurisdictions in which PSCo operates.

 

The retail electricbusiness does face some competition as industrial and large commercialcustomers have some ability to own or operate facilities to generate their ownelectricity. In addition, customers may have the option of substituting otherfuels, such as natural gas or steam/chilled water for heating, cooling andmanufacturing purposes, or the option of relocating their facilities to a lowercost region.  While PSCo faces thesechallenges, it believes its rates are competitive with currently availablealternatives.

 

**Summaryof Recent Federal Regulatory Developments**

 

The FERC has jurisdictionover rates for electric transmission service in interstate commerce andelectric energy sold at wholesale, 

 

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

 

***Market Based Rate Authority***— The FERCregulates the wholesale sale of electricity. In addition to FERC’s traditional cost of service methodology fordetermining the rates allowed to be charged for wholesale electric sales, inthe 1990’s FERC began to allow utilities to make sales at market-basedrates.  In order to obtain market-basedrate authorization from the FERC, utilities such as PSCo have been required tosubmit analyses demonstrating that they did not have market power in the relevantmarkets.  PSCo has been authorized byFERC to make wholesale sales at market-based rates.

 

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

 

In 2004, FERC initiated anew proceeding on future market-based rate authorizations and issued interimrequirements for FERC jurisdictional electric utilities that have been grantedauthority to make wholesale sales at market-based rates.  The FERC adopted a new interim methodology toassess generation market power and modified measures to mitigate market powerwhere it is found.  The FERC upheld andclarified the interim requirements on rehearing in an order issued on July 8,2004.  This methodology is to be appliedto all initial market-based rate applications and triennial reviews.  Under this methodology, the FERC has adoptedtwo indicative screens (an uncommitted pivotal supplier analysis and anuncommitted market share analysis) to assess market power.  Passage of the two screens creates arebuttable presumption that an applicant does not have market power, while thefailure creates a rebuttable presumption that the utility does have marketpower.  An applicant or intervenor canrebut the presumption by performing a more extensive delivered-price testanalysis.  If an applicant is determinedto have generation market power, the applicant has the opportunity to proposeits own mitigation plan or may implement default mitigation established by theFERC.  The default mitigation limitsprices for sales of power to cost-based rates within areas where an applicantis found to have market power.

 

As required by the FERC, XcelEnergy filed the required analysis applying the FERC’s two indicative screenson behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7,2005.  This analysis demonstrated thatPSCo failed the pivotal supplier analysis in its own control area and alladjacent markets, and the market share analysis in its own control area.  It is accordingly expected that the FERC willset the market-rate authorizations for PSCo for investigation and hearing underSection 206 of the Federal Power Act.  Atthat time, the PSCo expects to submit a delivered-price test analysis tosupport the continuance of market-based rate authority in its controlarea.  PSCo does not expect themitigation measures imposed, if any, to have a significant financial impact onits commodity marketing operations.

 

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

 

***Electric Transmission Rate Regulation***— The FERC also regulates the rates chargedand terms and conditions for electric transmission services.  Since 1996, the FERC has required PSCo toprovide open access transmission service at rates and tariffs on file with theFERC.  In addition, FERC policyencourages utilities to turn over the functional control over their electrictransmission assets and the related responsibility for the sale of electrictransmission services to an RTO.  EachRTO separately files for regional transmission tariff rates for approval byFERC.  All members within that RTO arethen subjected to those rates.  PSCo iscurrently participating with other utilities in the development of an RTO.

 

***Generation Interconnection Rules —***In August 2003, the FERC issued final rulesrequiring the standardization of generation interconnection procedures andagreements for interconnection of new electric generators of 20 megawatts ormore to the transmission systems of all FERC-jurisdictional electric utilities,including PSCo. The FERC also established pricing rules for interconnectionsand related transmission system upgrades, which allow the transmission-owningutility to require the interconnecting customer to fund the interconnectioncosts and network upgrades required by the new generator, but require thetransmission utility to provide transmission service credits, with interest,for the full amount of prepayment. The FERC required compliance filings fordetailing proposed changes to PSCo’s tariff, which will govern most generationinterconnections to the PSCo’s transmission system.  In October 2004, the FERC acceptedproposed tariff changes for PSCo, subject to certain conditions.  In November 2004, PSCo submitted a compliancefiling.  In

 

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

 

**Ratemaking Principles**

 

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

 

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

 

•                  *Electric Commodity Adjustment(ECA)*— The ECA, effectiveJan. 1, 2004, is an incentive adjustment mechanism that compares actual fueland purchased energy expense in a calendar year to a benchmark formula. The ECAthen provides for an $11.25 million cap on any cost sharing over or under anallowed ECA formula rate.  The formularate is revised annually and collected or refunded in the following year, ifnecessary.

 

•                  *Incentive Cost Adjustment(ICA) and Interim Adjustment Clause (IAC)*— The ICA allowed for an equal sharing between retail electriccustomers and shareholders of certain fuel and purchased energy costs andexpired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs isbeing amortized over the period June 1, 2002 through March 31, 2005.  For 2003, the IAC provided for the recoveryof prudently incurred fuel and energy costs not included in electric baserates.

 

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

 

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

 

•                  *Air-Quality ImprovementRider (AQIR)*— The AQIRrecovers, over a 15-year period, the incremental cost (including fuel andpurchased energy) incurred by PSCo as a result of a voluntary plan to reduceemissions and improve air quality in the Denver metro area.

 

•                  *Demand-Side Management CostAdjustment (DSMCA)*— TheDSMCA clause currently permits PSCo to recover DSM costs over five years whilenon-labor incremental expenses and carrying costs associated with deferred DSMcosts are recovered on an annual basis. PSCo also has a low-income energyassistance program. The costs of this energy conservation and weatherizationprogram for low-income customers are recovered through the DSMCA.

 

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

 

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

 

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

 

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

 

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

 

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

 

•                  an electric QSP that provides forbill credits to customers if PSCo does not achieve certain performance targetsrelating to electric reliability and customer service through 2006; and

 

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

 

PSCo regularly monitors andrecords as necessary an estimated customer refund obligation under the PBRP. InApril of each year following the measurement period, PSCo files its proposedrate adjustment under the PBRP. The CPUC conducts proceedings to review andapprove these rate adjustments annually.

 

•                  In 2002, PSCo did not earn a return on equityin excess of 10.5 percent, so no refund liability was recorded.  PSCo did not achieve the 2002 performancetargets for the electric service unavailability measure, creating a bill creditobligation for 2002 and increasing the maximum bill credit obligation forsubsequent years’ performance.  InDecember 2004, the CPUC approved a settlement resolving the earnings test for2002.

 

•                  In 2003, PSCo did not achieve the performancetargets for the QSP electric service unavailability measure or the customercomplaint measure.  Targets were met forthe natural gas QSP.  There was nosharing of earnings for 2003, as PSCo established new rates in its general ratecase.

 

•                  In 2004, PSCo does not anticipate earning areturn on equity in excess of 10.75 percent and did not record a refundliability.  QSP results will be filedwith the CPUC in April 2005.  Anestimated customer refund obligation under the electric QSP plan was recordedin 2004 related to the electric service unavailability measure.  No refund under the natural gas QSP isanticipated.

 

***Pending and Recently Concluded RegulatoryProceedings - FERC***

 

*PSCo and SPS FERC Transmission Rate Case*— On Sept. 2, 2004, Xcel Energy filedon behalf of PSCo and SPS an application to increase wholesale transmissionservice and ancillary service rates within the Xcel Energy joint open accesstransmission tariff.  PSCo and SPS areseeking an increase in annual transmission service and ancillary servicesrevenues of $6.1 million.  As a result ofa settlement with certain PSCo wholesale power customers in 2003, their powersales rates would be reduced by $1.4 million. The net increase in annualrevenues proposed is $4.7 million, of which $3.0 million is attributable toPSCo.  In December 2004, the FERCsuspended the filing and delayed the effective date of the proposed increase toMay 20, 2005.  The rate increaseapplication also includes PSCo and SPS adopting an annual formula rate fortransmission service pricing as previously approved by the FERC for othertransmission providers.  The case hasbeen set for hearing and settlement procedures.

 

*California Refund Proceeding —* A number ofparties purchasing energy in markets operated by the California IndependentSystem Operator (California ISO) or the California Power Exchange (PX) haveasserted prices paid for such energy were unjust and unreasonable and thatrefunds should be made in connection with sales in those markets for the periodOct. 2, 2000 through June 20, 2001. PSCo supplied energy to these marketsduring this period and has been an active participant in the proceedings. TheFERC ordered an investigation into the California ISO and PX spot markets andconcluded that the electric market structure and market rules for wholesalesales of energy in California were flawed and have caused unjust andunreasonable rates for short-term energy under certain conditions. The FERCordered modifications to the market structure and rules in California andestablished an ALJ to make findings with respect to, among other things, theamount of refunds owed by each supplier based on the difference between whatwas charged and what would have been charged in a more functional market, i.e.,the “market clearing price,” which is based on the unit providing energy in anhour with the highest incremental cost. The initial proceeding related toCalifornia’s demand for $8.9 billion in refunds from power sellers. The ALJsubsequently stated that after assessing a refund of $1.8 billion for powerprices, power suppliers were owed $1.2 billion because the state was holdingfunds owed to suppliers.

 

CertainCalifornia parties sought rehearing of this decision. Among other things, theyasserted that the refund effective date should be set at an earlier date. Theyhave based this request in part on the argument that the use by sellers ofcertain trading strategies in the California market resulted in unjust andunreasonable rates, thereby justifying an earlier refund effective date. TheFERC subsequently

 

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allowedthe purchasing parties to request from sellers, including PSCo, additionalinformation regarding the market participants’ use of certain strategies andthe effect those strategies may have had on the market. Based on the additionalinformation they obtained, these purchasing entities argued to the FERC thatuse of these strategies did justify an earlier refund effective date. TheseCalifornia entities have contended that PSCo would owe approximately $17million in refunds, if the FERC set the earlier refund effective date. InOctober 2003, the FERC determined that the refund effective date should not bereset to an earlier date, and gave clarification of how refunds should bedetermined for the previously set refund period. Certain California partiesappealed the FERC’s decision not to establish an earlier refund effective dateto the United States Court of Appeals for the Ninth Circuit.

 

In a related case, certain California parties also appealed the FERCorders dismissing a complaint by the California Attorney General challengingmarket-based rates as inconsistent with the Federal Power Act. The CaliforniaAttorney General also argued that wholesale sellers, including PSCo, wereviolating their market-based rate authorizations by not reporting theirmarket-based sales on an individual transaction basis. Prior to a clarificationof its rules, most sellers, including PSCo, reported their transactions on anaggregate basis. On Sept. 9, 2004, the United States Court of Appeals for theNinth Circuit issued an opinion rejecting the California Attorney General’sgeneral challenge to market-based rates, but agreeing with its challenge regardingthe failure to report individual transactions. It remanded the case to the FERCto consider action to take to address these failures and indicated that theFERC could require refunds.   Several ofthe intervenors in this appeal filed a petition for rehearing of this decisionin October 2004.  The rehearing requestis pending at the U.S. Court of Appeals for the Ninth Circuit.

 

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

 

PSCo has accrued its estimated minimum liability related to thesecases.  Because of the low volume ofsales that PSCo had into California, its exposure is estimated to beapproximately $7 million.  The FERC hasencouraged buyers and sellers in the organized California markets to try toresolve these cases through settlement, and PSCo is presently having settlementnegotiations with various California entities to try to reach a comprehensiveresolution of these cases.

 

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

 

*FERCInvestigation Against Wholesale Electric Sellers —*On June 25, 2003, the FERC issued two showcause orders addressing alleged improper market behavior in the Californiaelectricity markets. In the first show cause order, the FERC found that 24entities may have worked in concert through partnerships, alliances or otherarrangements to engage in activities that constitute gaming and/or anomalousmarket behavior. The FERC initiated proceedings against these 24 entitiesrequiring that they show cause why their behavior did not constitute gamingand/or anomalous market behavior. PSCo was not named in this order. In a secondshow cause order, the FERC indicated that various California parties, includingthe California ISO, have alleged that 43 entities individually engaged in oneor more of seven specific types of practices that the FERC has identified asconstituting gaming or anomalous market behavior within the meaning of theCalifornia ISO and California Power Exchange tariffs. PSCo was listed in anattachment to that show cause order as having been alleged to have engaged inone of the seven identified practices, namely circular scheduling. Subsequentto the show cause order, PSCo provided information to the FERC staff showingPSCo did not engage in circular scheduling. Subsequently, certain Californiaparties requested that FERC make PSCo subject to the show cause proceedingaddressing partnerships and expand the scope of the show cause order addressinggaming and/or anomalous market behavior to have PSCo address an allegation thatit engaged in another of the specified activities, namely “load shift.”

 

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

 

*PacificNorthwest FERC Refund Proceeding —*In July 2001, the FERC ordered a preliminary hearing to determinewhether there may have been unjust and unreasonable charges for spot marketbilateral sales in the Pacific Northwest for the period Dec. 25, 2000 throughJune 20, 2001. PSCo supplied energy to the Pacific Northwest markets duringthis period and has been an active participant in the hearings. In September2001, the presiding ALJ concluded that prices in the Pacific Northwest duringthe referenced period were the result of a number of factors, including theshortage of supply, excess demand, drought and increased natural gas prices.Under these circumstances the ALJ concluded that the prices in the PacificNorthwest markets were not unreasonable or unjust and no 

 

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

 

On June 25, 2003, the FERCissued an order terminating the proceeding without ordering furtherproceedings. On Nov. 10, 2003, in response to requests for rehearing, FERCreaffirmed this ruling to terminate the proceeding without refunds. Certainpurchasers have filed appeals of the FERC’s orders in this proceeding.

 

***Pending and Recently Concluded RegulatoryProceedings - CPUC***

 

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

 

In December2004, the CPUC approved a settlement resolving the earnings test and providingfor PSCo’s recovery of the actual cost of debt. It requires PSCo to spend an incremental $38 million, which will beincluded in rate base in future rate filings, in capital expenditures over thenext three years to improve system reliability and contribute $2 million toEnergy Outreach Colorado, a non-profit energy assistance organization.

 

*Quality of Service Plan* — The PSCo QSP provides for billcredits to Colorado retail customers, if PSCo does not achieve certainoperational performance targets. During the second quarter of 2004, PSCo filedits calendar year 2003 operating performance results for electric serviceunavailability, phone response time, customer complaints, accurate meterreading and natural gas leak repair time measures. PSCo did not achieve the2003 performance targets for the electric service unavailability measure or thecustomer complaint measure. Additionally, PSCo filed revisions to itspreviously filed 2002 electric QSP results for the service unavailabilitymeasure. Based on the revised results, PSCo did not achieve the 2002performance targets for the electric service unavailability measure, creating abill credit obligation for 2002 and increasing the maximum bill creditobligation for subsequent years’ performance.

 

As of Dec. 31,2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4million for the 2002 and 2003 calendar years. Based on the updated informationand filings discussed above, during the second quarter of 2004, PSCo increasedits estimated bill credit liability for these years to $13.4 million. PSCoposted the bill credits to retail customer accounts in the third quarter of2004. For calendar year 2004, PSCo has evaluated its performance under the QSPand has recorded a liability of $11 million. Under the electric QSP, the estimated maximum potential bill creditobligation for calendar 2004 performance is approximately $15.2 million,assuming none of the performance targets are met.  The maximum potential bill credit obligationfor the same period related to permanent natural gas leak repair and naturalgas meter reading errors is approximately $1.6 million.

 

*Incentive CostAdjustment and Interim Adjustment Clause —*PSCo’s ICA mechanism was in place for periodsprior to 2003.  The costs included in theICA were subject to review by the CPUC. In a CPUC docket reviewing the 2001 ICA, the CPUC approved a settlementthat, among other things, provided for a prospective revenue adjustment relatedto the maximum allowable natural gas hedging costs that would be a part of theelectric commodity adjustment for 2004, which reduced 2004 rates by $4.6million.  In 2004, the CPUC approved the2002 fuel and purchased energy costs reflected in the ICA.  PSCo agreed to amortize the 2002 ICA costsover the period of June 2002 through March 2005.  In 2003, PSCo’s prudently incurred fuel andpurchased energy costs were fully recoverable under the IAC and are stillsubject to a future review by the CPUC. On Aug. 2, 2004, PSCo applied to the CPUC for approval of its 2003 fueland purchased energy costs.  This applicationis pending before the CPUC.

 

*Electric Trading Docket*****— As part of the settlement of the2002 PSCo general rate case, the parties agreed that PSCo would initiate adocket regarding the status of wholesale electric trading after 2004. Theproceeding was initiated on Jan. 30, 2004. PSCo’s testimony proposed certainrevisions to the business rules governing trading transactions; to continueelectric trading on both a generation book and commodity book basis; toestablish a defined trading benefit for electric retail customers and to begintrading natural gas as a risk mitigation measure in support of its electrictrading. On July 8, 2004, the staff of the CPUC filed testimony regardingelectric trading. The staff raised issues related to the computer model used toallocate costs to trading transactions, PSCo’s ability to track transactionsindividually, instead of in aggregate, for each hour and the allocation ofsystem costs. The staff requested additional reporting through 2006.

 

PSCo, thestaff of the CPUC and the OCC reached full settlement of the disputed issues onSept. 10, 2004. The CPUC approved the settlement on Oct. 5, 2004. Thesettlement modifies the rules governing trading transactions to provide morespecificity as to 

 

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transactionpriorities, record retention and cost assignment.  The CPUC acknowledged the benefit ofcommodity trading.  Consequently, thesettlement provides for continuation of electric commodity trading as currentlyconducted by PSCo, and permits PSCo to begin trading natural gas as a riskmitigation measure in support of its electric trading.  PSCo anticipates commencing natural gastrading activities as permitted by the settlement in the first half of2005.  The settlement also provides forthe margin sharing mechanisms that are currently in place in the PSCo retailrates to continue through 2006. Finally, the settlement requires thecooperative development of auditing processes to provide the staff of the CPUCwith information regarding PSCo’s trading operations and for the filing ofmonthly reports with respect to these trading operations.  This proceeding is now complete.

 

**Capacity and Demand**

 

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

 
| **System  Peak Demand (in Megawatts)** |
|----------------------------------------|
| **2002**                               | ** ** | **2003** | ** ** | **2004** | ** ** | **2005  Forecast** |
| ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 5,872                                  |   | 6,419 |   | 6,444 |   | 6,557 |

 

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

 

# **Energy Sources** and RelatedTransmission Initiatives

# ** **

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

 

***Purchased Power***— PSCo has contractual arrangements to purchase power from otherutilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate atwhich a particular generating source produces electricity.  Energy, typically measured in Kwh or Mwh, isa measure of the amount of electricity produced from a particular generatingsource over a period of time.  Long-termpurchase power contracts typically require a periodic payment to secure thecapacity from a particular generating source and a charge for the associatedenergy actually purchased from such generating source.

 

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

 

***PSCo Resource Plan***— PSCo estimates it will purchase approximately 40 percent of its totalelectric system energy input for 2005. Approximately 48 percent of the totalsystem capacity for the summer 2005 system peak demand for PSCo will beprovided by purchased power.

 

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

 

On Dec. 17,2004, the CPUC approved a settlement agreement between PSCo and manyintervening parties concerning the LCRP. PSCo received the formal written decision of the CPUC in January2005.  The CPUC approved PSCo’s plan toconstruct a 750-MW pulverized coal-fired unit at the Comanche Station locatednear Pueblo, Colo. and transfer up to 250 MW of capacity ownership from the750-MW unit to Intermountain Rural Electric Association and Holy Cross Energy,if negotiations with those entities are successful.  The settlement agreement also enables PSCo toacquire resources through an all-source competitive bidding process.

 

Among other things, theapproved settlement allows for additional emission controls to be installed andassociated costs to be collected from customers at Comanche Station’s twoexisting coal-fired units.  Thesettlement contains a confidential construction cost 

 

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cap for the constructionof the 750-MW Comanche 3 unit.  It alsoincludes a regulatory plan that authorizes PSCo to increase the equitycomponent of its capital structure to 56 percent in its 2006 rate case tooffset the debt equivalent value of PSCo’s existing purchased power agreementsand to otherwise improve PSCo’s financial strength.  Depending upon PSCo’s senior unsecured debtrating during the time of PSCo general rates cases, the approved settlementpermits PSCo to include various amounts of construction work in progress inrate base without an allowance for funds used during construction offsetassociated with the Comanche 3 generating unit, additional emission controls onthe Comanche 1 and 2 generating units and associated transmission.  PSCo agreed to invest in additionaldemand-side management, accelerate the completion of an ongoing wind-saturationstudy and fund environmental programs in Pueblo, Colo.

 

In a separate docket, theCPUC granted PSCo’s request for approval of a 500-MW renewable energysolicitation.  PSCo issued a request forproposal, with bids to be submitted in November 2004.  PSCo is currently negotiating contracts withbidders of approximately 328 MW of renewable energy.

 

***Purchased Transmission Services***— PSCo has contractual arrangements withregional transmission service providers to deliver power and energy to thesubsidiaries’ native load customers, which are retail and wholesale loadobligations with terms of more than one year. Point-to-point transmission services typically include a charge for thespecific amount of transmission capacity being reserved, although someagreements may base charges on the amount of metered energy delivered.  Network transmission services include acharge for the metered demand at the delivery point at the time of the provider’smonthly transmission system peak, usually calculated as a 12-month rollingaverage.

 

**Fuel Supply and Costs**

 

The following table showsthe delivered cost MMBtu of each significant category of fuel consumed forelectric generation, the percentage of total fuel requirements represented byeach category of fuel and the total weighted average cost of all fuels duringsuch years.

 
| ** ** | ** ** | **Coal**   | ** ** | **Natural Gas** | ** ** | **Average Fuel** | ** ** |
|------------|------------|------------|------------|-----------------|------------|------------------|------------|
| ** ** | ** ** | **Cost**   | ** ** | **Percent**     | ** ** | **Cost**         | ** ** | **Percent** | ** ** | **Cost** | ** ** |
| ** ** | ** ** | ** ** | ** ** | ** **      | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** |
| 2004       |       | $          | 0.89       |            | 87         | %                | $          | 5.61 |   | 13 | % | $ | 1.52 |   |
| 2003       |       | $          | 0.92       |            | 86         | %                | $          | 4.49 |   | 14 | % | $ | 1.42 |   |
| 2002       |       | $          | 0.91       |            | 79         | %                | $          | 2.25 |   | 21 | % | $ | 1.19 |   |

 

***Fuel Sources ***—******PSCo’s generation stations use low-sulfurwestern coal purchased primarily under long-term contracts with suppliersoperating in Colorado and Wyoming. During 2004, PSCo’s coal requirements forexisting plants were approximately 9.8 million tons, a substantial portion ofwhich was supplied pursuant to long-term supply contracts. Coal supplyinventories at Dec. 31, 2004 were approximately 41 days usage, based on theaverage burn rate for all of PSCo’s coal-fired plants.

 

PSCo operates the Haydengenerating plant in Colorado.  All ofHayden’s coal requirements are supplied under a long-term agreement.  The Hayden facility is located in closeproximity to a coal mine, which has historically provided the coal to fulfillHayden’s fuel requirements under the long-term agreement.  The mine operator has announced that the minewill close near the end of 2005.  PSCo iscurrently investigating a number of alternatives to provide for anuninterrupted, economical fuel supply to the facility.  It is anticipated that total fuel costs willincrease following the closure of the mine, however, the amount of increasedcosts, if any, cannot be determined at this time.  In addition to Hayden, PSCo has partialownership in the Craig generating plant in Colorado.  Approximately 70 percent of PSCo’s coalrequirements for Craig are supplied by two long-term agreements.

 

PSCo has contracted for coalsuppliers to supply approximately 98 percent of the Cherokee, Cameo, Valmontand remaining Craig stations’ projected requirements in 2005.

 

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

 

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

 

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of PSCo’s coal-basedgeneration facilities.  However, it isexpected that coal transportation costs will increase.  Currently, the impact or extent of theincrease cannot be determined.

 

PSCo uses both firm andinterruptible natural gas and standby oil in combustion turbines and certainboilers. Natural gas supplies for PSCo’s power plants are procured under short-and intermediate-term contracts to provide an adequate supply of fuel.

 

**CommodityMarketing Operations**

 

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

 

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**PSCo ElectricOperating Statistics**

 
| ** **                                | ** ** | **Year Ended Dec. 31,** | ** ** |
|-------------------------------------------|------------|-------------------------|------------|
| ** **                                | ** ** | **2004**                | ** ** | **2003** | ** ** | **2002** | ** ** |
| Electric sales (Millions of Kwh):         |       |                    |       |   |   |   |   |
| Residential                               |       | 8,066                   |       | 8,251 |   | 8,129 |   |
| Commercial and industrial                 |       | 17,409                  |       | 17,307 |   | 17,408 |   |
| Public authorities and other              |       | 252                     |       | 289 |   | 277 |   |
| Total retail                              |       | 25,727                  |       | 25,847 |   | 25,814 |   |
| Sales for resale                          |       | 8,372                   |       | 6,594 |   | 8,701 |   |
| Total energy sold                         |       | 34,099                  |       | 32,441 |   | 34,515 |   |
|                                      |       |                    |       |   |   |   |   |
| Number of customers at end of period:     |       |                    |       |   |   |   |   |
| Residential                               |       | 1,083,872               |       | 1,078,394 |   | 1,058,082 |   |
| Commercial and industrial                 |       | 144,111                 |       | 144,991 |   | 139,573 |   |
| Public authorities and other              |       | 66,797                  |       | 68,452 |   | 68,601 |   |
| Total retail                              |       | 1,294,780               |       | 1,291,837 |   | 1,266,256 |   |
| Wholesale                                 |       | 69                      |       | 70 |   | 171 |   |
| Total customers                           |       | 1,294,849               |       | 1,291,907 |   | 1,266,427 |   |
|                                      |       |                    |       |   |   |   |   |
| Electric revenues (Thousands of dollars): |       |                    |       |   |   |   |   |
| Residential                               |       | $                       | 672,496    |   | $ | 686,627 |   | $ | 585,035 |   |
| Commercial and industrial                 |       | 1,080,660               |       | 1,059,143 |   | 866,955 |   |
| Public authorities and other              |       | 36,257                  |       | 38,775 |   | 32,803 |   |
| Total retail                              |       | 1,789,413               |       | 1,784,545 |   | 1,484,793 |   |
| Wholesale                                 |       | 403,155                 |       | 315,589 |   | 355,713 |   |
| Other electric revenues                   |       | 2,060                   |       | 17,656 |   | 37,687 |   |
| Total electric revenues                   |       | $                       | 2,194,628  |   | $ | 2,117,790 |   | $ | 1,878,193 |   |
|                                      |       |                    |       |   |   |   |   |
| Kwh sales per retail customer             |       | 19,870                  |       | 20,008 |   | 20,386 |   |
| Revenue per retail customer               |       | $                       | 1,382.02   |   | $ | 1,381.40 |   | $ | 1,172.59 |   |
| Residential revenue per Kwh               |       | 8.34                    | ¢     | 8.32 | ¢ | 7.20 | ¢ |
| Commercial and industrial revenue per Kwh |       | 6.21                    | ¢     | 6.12 | ¢ | 4.98 | ¢ |
| Wholesale revenue per Kwh                 |       | 4.82                    | ¢     | 4.79 | ¢ | 4.09 | ¢ |

 

16

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**NATURAL GASUTILITY OPERATIONS**

 

**Summary of Recent Regulatory Development****s**

 

Changes in regulatorypolicies and market forces have shifted the industry from traditional bundlednatural gas sales service to an unbundled transportation and market-basedcommodity service at the wholesale level and for larger commercial andindustrial retail customers. These customers have greater ability to buynatural gas directly from suppliers and arrange their own pipeline and retailLDC transportation service.

 

The natural gas delivery andtransportation business has remained competitive as industrial and largecommercial customers have the ability to bypass the local natural gas utilitythrough the construction of interconnections directly with interstatepipelines, thereby avoiding the delivery charges added by the local natural gasutility.

 

As an LDC, PSCo providesunbundled transportation service to large customers. Transportation servicedoes not have an adverse effect on earnings because the sales andtransportation rates have been designed to make them economically indifferentto whether natural gas has been sold and transported or merely transported.However, some transportation customers may have greater opportunities orincentives to physically bypass the LDCs distribution system.

 

The most significant recentdevelopments in the natural gas operations of PSCo are the substantial and continuingincreases in wholesale natural gas market prices and the continued trend towarddeclining use per customer by residential customers as a result of improvedbuilding construction technologies and higher appliance efficiencies.  From 1994 to 2004, average annual sales tothe typical residential customer declined from 109 Dth per year to 87 Dth peryear on a weather-normalized basis. Although recent wholesale price increases do not directly affectearnings because of gas cost recovery mechanisms, the high prices are expectedto encourage further efficiency efforts by customers.

 

# **RatemakingPrinciples**

# ** **

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

 

***Purchased Gas and Conservation Cost Recovery Mechanisms*******—****PSCohas a GCA mechanism, which allows PSCo to recover its actual costs of purchasedgas.  Effective Nov. 1, 2004, the GCA isrevised monthly to allow for changes in gas rates.  Previously, the GCA rate was revised at leastannually to coincide with changes in purchased gas costs.

 

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

 

# **Capability andDemand**

# ** **

PSCo projects peak daynatural gas supply requirements for firm sales and backup transportation, whichinclude transportation customers contracting for firm supply backup, to be1,781,088 MMBtu. In addition, firm transportation customers hold 477,419 MMBtuof capacity without supply backup. Total firm delivery obligation is 2,258,507MMBtu per day. The maximum daily deliveries for PSCo in 2004 for firm andinterruptible services were 1,860,958 MMBtu on Jan. 5, 2004.

 

PSCo purchases natural gasfrom independent suppliers. The natural gas supplies are delivered to therespective delivery systems through a combination of transportation agreementswith interstate pipelines and deliveries by suppliers directly to each company.These agreements provide for firm deliverable pipeline capacity ofapproximately 1,792,543 MMBtu/day, which includes 826,866 MMBtu of suppliesheld under third-party underground storage agreements. In addition, PSCooperates three company-owned underground storage facilities, which provideabout 40,000 MMBtu of natural gas supplies on a peak day. The balance of thequantities required to meet firm peak day sales obligations are primarilypurchased at the companies’ city gate meter stations and a small amount isreceived directly from wellhead sources.

 

PSCo has received approvaland is in the process of closing the Leyden Storage Field. The field’s 110,000MMBtu peak day capacity was replaced with additional third-party storage andtransportation capacity. See further discussion at Note 12 to the ConsolidatedFinancial Statements.

 

17

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

 

**Natural Gas Supply and Costs**

 

PSCo actively seeks naturalgas supply, transportation and storage alternatives to yield a diversifiedportfolio that provides increased flexibility, decreased interruption andfinancial risk, and economical rates. This diversification involves numeroussupply sources with varied contract lengths.

 

The following tablesummarizes the average cost per MMBtu of natural gas purchased for resale byPSCo’s regulated retail natural gas distribution business:

 
| 2004 |   | $ | 6.30 |   |
|------|--------|---|------|--------|
| 2003 |   | $ | 4.94 |   |
| 2002 |   | $ | 3.17 |   |

 

The cost of natural gassupply, transportation service and storage service is recovered through variouscost recovery adjustment mechanisms.

 

PSCo has certain natural gassupply and transportation agreements that include obligations for the purchaseand/or delivery of specified volumes of natural gas or to make payments in lieuof delivery. At Dec. 31, 2004, PSCo was committed to approximately $1.5 billionin such obligations under these contracts, which expire in various years from2005 through 2025.

 

PSCo purchases natural gasby optimizing a balance of long-term and short-term natural gas purchases, firmtransportation and natural gas storage contracts. PSCo also utilizes a mixtureof fixed-price purchases and index-related purchases to provide a lessvolatile, yet market-sensitive, price to its customers. During 2004, PSCopurchased natural gas from approximately 37 suppliers.

 

18

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**PSCo Natural GasOperating Statistics**

 
| ** **                                    | ** ** | **Year Ended Dec. 31,** | ** ** |
|-----------------------------------------------|------------|-------------------------|------------|
| ** **                                    | ** ** | **2004**                | ** ** | **2003** | ** ** | **2002** | ** ** |
| Natural gas deliveries (Thousands of Dth):    |       |                    |       |   |   |   |   |
| Residential                                   |       | 88,726                  |       | 91,513 |   | 95,882 |   |
| Commercial and industrial                     |       | 38,501                  |       | 41,545 |   | 43,449 |   |
| Total retail                                  |       | 127,227                 |       | 133,058 |   | 139,331 |   |
| Transportation and other                      |       | 102,139                 |       | 104,430 |   | 120,626 |   |
| Total deliveries                              |       | 229,366                 |       | 237,488 |   | 259,957 |   |
|                                          |       |                    |       |   |   |   |   |
| Number of customers at end of period:         |       |                    |       |   |   |   |   |
| Residential                                   |       | 1,111,377               |       | 1,089,958 |   | 1,063,378 |   |
| Commercial and industrial                     |       | 94,414                  |       | 98,066 |   | 96,669 |   |
| Total retail                                  |       | 1,205,791               |       | 1,188,024 |   | 1,160,047 |   |
| Transportation and other                      |       | 3,506                   |       | 3,264 |   | 3,134 |   |
| Total customers                               |       | 1,209,297               |       | 1,191,288 |   | 1,163,181 |   |
|                                          |       |                    |       |   |   |   |   |
| Natural gas revenues (Thousands of  dollars): |       |                    |       |   |   |   |   |
| Residential                                   |       | $                       | 742,724    |   | $ | 599,883 |   | $ | 510,890 |   |
| Commercial and industrial                     |       | 288,002                 |       | 240,084 |   | 192,419 |   |
| Total retail                                  |       | 1,030,726               |       | 839,967 |   | 703,309 |   |
| Transportation and other                      |       | 43,263                  |       | 43,085 |   | 46,046 |   |
| Total natural gas revenues                    |       | $                       | 1,073,989  |   | $ | 883,052 |   | $ | 749,355 |   |
|                                          |       |                    |       |   |   |   |   |
| Dth sales per retail customer                 |       | 105.51                  |       | 112.00 |   | 120.11 |   |
| Revenue per retail customer                   |       | $                       | 854.81     |   | $ | 707.03 |   | $ | 606.28 |   |
| Residential revenue per Dth                   |       | $                       | 8.37       |   | $ | 6.56 |   | $ | 5.33 |   |
| Commercial and industrial revenue per Dth     |       | $                       | 7.48       |   | $ | 5.78 |   | $ | 4.43 |   |
| Transportation and other revenue per Dth      |       | $                       | 0.42       |   | $ | 0.41 |   | $ | 0.38 |   |

 

19

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# **ENVIRONMENTAL MATTERS**

# ** **

PSCo’s facilities areregulated by federal and state environmental agencies. These agencies havejurisdiction over air emissions, water quality, wastewater discharges, solidwastes and hazardous substances. Various company activities require registrations,permits, licenses, inspections and approvals from these agencies.  PSCo has received all necessaryauthorizations for the construction and continued operation of its generation,transmission and distribution systems. Company facilities have been designedand constructed to operate in compliance with applicable environmentalstandards.

 

PSCo strives to comply withall environmental regulations applicable to its operations. However, it is notpossible at this time to determine when or to what extent additional facilitiesor modifications of existing or planned facilities will be required as a resultof changes to environmental regulations, interpretations or enforcementpolicies or, generally, what effect future laws or regulations may have uponits operations. For more information on environmental contingencies, see Note12 to the Consolidated Financial Statements and the matter discussed below.

 

# **EMPLOYEES**

# ** **

The number of full-time PSCoemployees on Dec. 31, 2004 was 2,610. Of these full-time employees, 2,177, or83 percent, are covered under collective bargaining agreements. See Note 8 tothe Consolidated Financial Statements for further discussion. Xcel EnergyServices Inc. a subsidiary of Xcel Energy, employees provide services to PSCo.

 

**Item 2**— **Properties**

 

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

 

Electric utility generatingstations: 

 

| **Station, City and  Unit**                               | ** ** | **Fuel**         | ** ** | **Installed**    | ** ** | **Summer 2004 Net  Dependable  Capability (MW)** | ** ** |
|-----------------------------------------------------------|------------|------------------|------------|------------------|------------|--------------------------------------------------|------------|
| ***Steam:***                                              |       |             |       |             |       |                                             |       |
| Arapahoe —Denver, Colo.  2 Units                     |       | Coal             |       | 1950 – 1955 |       | 156                                              |       |
| Cameo — Grand Junction, Colo.  2 Units               |       | Coal             |       | 1957 – 1960 |       | 73                                               |       |
| Cherokee — Denver, Colo.  4 Units                    |       | Coal             |       | 1957 – 1968 |       | 717                                              |       |
| Comanche — Pueblo, Colo.  2 Units                    |       | Coal             |       | 1973 – 1975 |       | 660                                              |       |
| Craig — Craig, Colo.  2 Units (a)                    |       | Coal             |       | 1979 – 1980 |       | 83                                               |       |
| Hayden — Hayden, Colo.  2 Units (b)                  |       | Coal             |       | 1965 – 1976 |       | 237                                              |       |
| Pawnee — Brush, Colo                                 |       | Coal             |       | 1981             |       | 505                                              |       |
| Valmont — Boulder, Colo                              |       | Coal             |       | 1964             |       | 186                                              |       |
| Zuni — Denver, Colo.  3 Units                        |       | Natural  Gas/Oil |       | 1948 – 1954 |       | 107                                              |       |
| ***Combustion Turbines:***                                |       |             |       |             |       |                                             |       |
| Fort St. Vrain — Platteville, Colo.  4 Units         |       | Natural Gas      |       | 1972 – 2001 |       | 690                                              |       |
| Various Locations  6 Units                                |       | Natural Gas      |       | Various          |       | 185                                              |       |
| ***Hydro:***                                              |       |             |       |             |       |                                             |       |
| Various Locations 12 Units                                |       |             |       | Various          |       | 32                                               |       |
| Cabin Creek — Georgetown, Colo - Pumped  Storage     |       |             |       | 1967             |       | 210                                              |       |
| ***Wind:***                                               |       |             |       |             |       |                                             |       |
| Ponnequin — Weld County, Colo                        |       |             |       | 1999 – 2001 |       | —                                           |       |
| ***Diesel:***                                             |       |             |       |             |       |                                             |       |
| Diesel Generators: Cherokee — Denver, Colo.  2 Units |       |             |       | 1967             |       | 6                                                |       |
| Total                                                     |       |             |       |             |       | 3,847                                            |       |

----

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

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

 

 

20

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Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2004:

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

 

PSCo had 212 electricutility transmission and distribution substations at Dec. 31, 2004.

 

Natural gas utility mains atDec. 31, 2004:

 
| **Miles**    | ** ** |
|--------------|------------|
| Transmission |       | 2,287 |   |
| Distribution |       | 19,027 |   |

 

**Item 3**— **Legal Proceedings**

 

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

 

***Other Matters***

 

For more discussion of legalclaims and environmental proceedings, see Note 12 to the Consolidated FinancialStatements under Item 8, incorporated by reference. For a discussion ofproceedings involving utility rates, see Pending and Recently ConcludedRegulatory Proceedings under Item 1, incorporated by reference.

 

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

 

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

 

**PART II**

 

**Item 5**—**Market for Registrant’s Common****Equity, Related StockholderMatters and****IssuerPurchases of Equity Securities**

 

PSCo is a wholly ownedsubsidiary of Xcel Energy and there is no market for its common equitysecurities.

 

PSCo has dividendrestrictions imposed by debt agreements and the SEC under the PUHCA limitingthe amount of dividends PSCo can pay to Xcel Energy. These restrictionsinclude, but may not be limited to, the following:

 

•            maintenance of a minimum equity ratio of 30percent;

•            payment of dividends only from retainedearnings; and

•            debt covenant restriction under the creditagreement for debt ratio.

 

21

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

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

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

 

**Item 6**— **Selected Financial Data**

 

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

 

**Item 7**— **Management’sDiscussion and Ana****lysis of Financial Condition and Results of Operations**

 

Discussion of financialcondition and liquidity for PSCo is omitted per conditions set forth in generalinstructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It isreplaced with management’s narrative analysis and the results of operations forthe current year as set forth in general instructions I(2)(a) of Form 10-K forwholly owned subsidiaries (reduced disclosure format).

 

**ForwardLooking Information**

 

The following discussion andanalysis by management focuses on those factors that had a material effect onthe financial condition and results of operations of PSCo during the periodspresented, or are expected to have a material impact in the future. It shouldbe read in conjunction with the respective accompanying Consolidated FinancialStatements and Notes to the Consolidated Financial Statements.

 

Except for the historicalstatements contained in this report, the matters discussed in the followingdiscussion and analysis are forward-looking statements that are subject tocertain risks, uncertainties and assumptions. Such forward-looking statementsare 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 mayvary materially. Factors that could cause actual results to differ materiallyinclude, but are not limited to:

 

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

•                  rating agency actions;

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

•                  business conditions in the energy industry;

•                  competitive factors including the extent andtiming of the entry of additional competition;

•                  unusual weather;

•                  changes in federal or state legislation;

•                  geopolitical events, including war and actsof terrorism;

•                  regulation; and

•                  the other risk factors listed from time totime PSCo in reports filed with the SEC, including Exhibit 99.01 to this AnnualReport on Form 10-K for the year ended Dec. 31, 2004.

 

## **Management’s Discussion and Analysis of FinancialCondition and Results of Operation**

 

**Results OfOperations**

 

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

 

***Electric Utility, Short-Term Wholesale and Commodity Trading Margins*****— Electric fuel and purchased power expensestend to vary with changing retail and wholesale sales requirements and unitcost changes in fuel and purchased power. Due to fuel cost 

 

22

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recovery mechanisms forretail customers, most fluctuations in energy costs do not significantly affectelectric utility margin.

 

PSCo has two distinct formsof wholesale sales: short-term wholesale and commodity trading. Short-termwholesale refers to energy related purchase and sales activity and the use ofcertain financial instruments associated with the fuel required for and energyproduced from PSCo’s generation assets and energy and capacity purchased toserve native load.  Commodity trading isnot associated with PSCo’s generation assets or the energy and capacitypurchased to serve native load.

 

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

 
| **(Millions of dollars)**                               | ** ** | **Base  Electric  Utility** | ** ** | **Short-Term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Totals** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|--------------------------|------------|
| **2004**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenue (excluding  commodity trading) |       | $                           | 2,128      |                      | $          | 67                     |       | $                        | —     |   | $ | 2,195 |   |
| Electric fuel and purchased power                       |       | (1,181                      | )          | (62                       | )          | —                 |       | (1,243                   | )          |
| Commodity trading revenue                               |       | —                      |       | —                    |       | 472                    |       | 472                      |       |
| Commodity trading costs                                 |       | —                      |       | —                    |       | (473                   | )          | (473                     | )          |
| Gross margin before operating expenses                  |       | $                           | 947        |                      | $          | 5                      |       | $                        | (1         | ) | $ | 951 |   |
| Margin as a percentage of revenue                       |       | 44.5                        | %          | 7.5                       | %          | (0.2%                  | )          | 35.7                     | %          |
|                                                    |       |                        |       |                      |       |                   |       |                     |       |
| **2003**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenue (excluding  commodity trading) |       | $                           | 2,073      |                      | $          | 45                     |       | $                        | —     |   | $ | 2,118 |   |
| Electric fuel and purchased power                       |       | (1,107                      | )          | (45                       | )          | —                 |       | (1,152                   | )          |
| Commodity trading revenue                               |       | —                      |       | —                    |       | 234                    |       | 234                      |       |
| Commodity trading costs                                 |       | —                      |       | —                    |       | (235                   | )          | (235                     | )          |
| Gross margin before operating expenses                  |       | $                           | 966        |                      | $          | —                 |       | $                        | (1         | ) | $ | 965 |   |
| Margin as a percentage of revenue                       |       | 46.6                        | %          | —                    | %          | (0.4                   | )%         | 41.0                     | %          |
|                                                         |            |                             |            |                           |            |                        |            |                          |            |  |  |  |  |  |  |  |

 

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

 

***Base Electric Revenue***

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

 

***Base Electric Margin***

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

 

23

 

***Natural Gas Utility Margins*****— The following table details the change innatural gas revenue and margin. The cost of natural gas tends to vary withchanging sales requirements and unit cost of natural gas purchases. PSCo has aGCA mechanism for natural gas sales, which recognizes the majority of theeffects of changes in the cost of natural gas purchased for resale and adjustsrevenues to reflect such changes in costs upon request by PSCo.  Therefore, fluctuations in the cost ofnatural gas have little effect on natural gas margin.

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

 

The following summarizes thecomponents of the changes in natural gas revenue and margin for the year endedDec. 31:

 

***Natural Gas Revenue***

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

 

Natural gasrevenue increased primarily due to higher natural gas costs in 2004, which arepassed through to customers.

 

###### ***Natural Gas Margin***

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

 

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

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

 

24

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Depreciation andamortization expense decreased by approximately $3.3 million, or 1.5 percent,for 2004 compared with 2003.  EffectiveJuly 1, 2003, the CPUC lengthened the depreciable lives of certain electricutility plant at PSCo as a part of the general Colorado rate case, whichreduced annual depreciation expense by about $20 million.  This action reduced 2003 depreciation expenseby $10 million.  PSCo’s depreciationexpense in 2004 reflects the full year impact of this change.  Partially offsetting the decrease is anincrease related to plant additions.

 

Taxes (other than incometaxes) increased by approximately $3.3 million, or 3.9 percent, for 2004compared with 2003, primarily due to higher property taxes for calendar year2004.

 

Other income (expense)increased by approximately $8.5 million primarily due to an interest accrualfor proceeds expected to be received as a result of  filing amended tax returns for 1995 through2003.

 

Interest charges andfinancing costs decreased by approximately $9.3 million, or 5.8 percent, for2004 compared with 2003, primarily due to the issuance of debt during 2003 torefinance higher coupon debt, including the redemption of the preferredsecurities of PSCo’s subsidiary trust.

 

Income tax expense decreasedby approximately $15.4 million in 2004, compared with 2003.  The decrease was primarily due to lowerincome levels and a decrease in the permanent tax adjustment for regulatoryplant items.  The effective tax rate was25.0 percent for the period ended Dec. 31, 2004, compared with 27.9 percent forthe same period in 2003.  Significant taxbenefits were recorded during both periods due to the resolution of tax auditissues, largely related to prior periods, as discussed below.

 

The significant auditactivity that occurred late in 2003 continued in 2004.  During 2004 PSCo concluded IRS incometax audit and appeal activities spanning several examination cycles dating backto 1993.  In addition, the IRS nearlycompleted the examination cycle ended 2001 and began its review of the PSCo’s2002 and 2003 tax years.

 

Income taxbenefits of $14.2 million were recorded in 2004, including $12.9 millionrelated to the successful resolution of various IRS audit issues and otheradjustments to current and deferred taxes related to prior years and $1.3million for the 2003 return to accrual true-up. Excluding the tax benefits, the effective rate for the year 2004 wouldhave been 29.9 percent.

 

The income taxexpense recorded in 2003 included $9.2 million in tax benefits to reflect thesuccessful resolution of various open tax audit issues related to prioryears.  The main issue resolved was thetax deductibility of certain merger costs associated with the merger to formXcel Energy and NCE.  Excluding these taxbenefits, the effective rate for the year 2003 would have been 30.8 percent.

 

**Item 7A**— **Quantitativeand Qualitative D****isclosures About Market Risk**

 

**Derivatives,Risk Management and Market Risk**

 

In the normal course of business, PSCo is exposed to a variety ofmarket risks.  Market risk is thepotential loss that may occur as a result of changes in the market or fairvalue 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 inits generation and retail distribution operations.  Commodity price risk is managed by enteringinto both long- and short-term physical purchase and sales contracts forelectric power, natural gas, coal and fuel oil. Commodity price risk is also managed through the use of financialderivative instruments.  PSCo’s riskmanagement policy allows it to manage commodity price risk within eachrate-regulated operation to the extent such exposure exists.

 

***Short-Term Wholesale and Commodity Trading Risk —***PSCo conducts various commodity-marketingactivities, including the purchase and sale of capacity, energy and energyrelated instruments. These marketing activities are primarily focused onspecific regions where market knowledge and experience have been obtained andare generally less than one year in length. PSCo’s risk management policy allows management to conduct the marketingactivities within approved guidelines and limitations as approved by thecompany’s risk management committee, which is made up of management personnelnot directly involved in the activities governed by the policy.

 

25

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

 

See Note 10 to theConsolidated Financial Statements for a discussion of the various trading andhedging contracts of PSCo.

 

PSCo’s short-term wholesaleand commodity trading operations measure the outstanding risk exposure to pricechanges on transactions, contracts and obligations that have been entered into,but not closed, using an industry standard methodology known as VaR. VaRexpresses the potential change in fair value on the outstanding transactions,contracts and obligations over a particular period of time, with a givenconfidence interval under normal market conditions. PSCo utilizes thevariance/covariance approach in calculating VaR. The VaR model employs a95-percent confidence interval level based on historical price movement,lognormal price distribution assumption, delta half-gamma approach fornon-linear instruments and a three-day holding period for both electricity andnatural gas.  Previously, PSCo calculatedVaR using a holding period of five days for electricity and two days fornatural gas.  However, the methodologywas changed to ensure consistency in risk measurement across bothcommodities.  PSCo’s revised holdingperiods remain consistent with current industry practice.  VaR using the current methodology for 2004and previous methodology for 2003 are as follows:

 

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

 
| **Current Methodology**   | ** ** | **Year ended**    | ** ** | **During 2004** | ** ** |
|---------------------------|------------|-------------------|------------|-----------------|------------|
| **(Millions of dollars)** | ** ** | **Dec. 31, 2004** | ** ** | **Average**     | ** ** | **High** | ** ** | **Low** | ** ** |
| ** **                | ** ** | ** **        | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity trading (a)     |       | $                 | 0.29       |            | $          | 0.97 |   | $ | 2.09 |   | $ | 0.27 |   |
|                           |            |                   |            |                 |            |  |  |  |  |  |  |  |  |

 

----

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

 

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

 
| **Previous Methodology**       | ** ** | **Year ended**    | ** ** | **During 2003** | ** ** |
|--------------------------------|------------|-------------------|------------|-----------------|------------|
| **(Millions of dollars)**      | ** ** | **Dec. 31, 2003** | ** ** | **Average**     | ** ** | **High** | ** ** | **Low** | ** ** |
| ** **                     | ** ** | ** **        | ** ** | ** **      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Electric commodity trading (a) |       | $                 | 0.92       |            | $          | 0.70 |   | $ | 1.51 |   | $ | 0.29 |   |
|                                |            |                   |            |                 |            |  |  |  |  |  |  |  |  |

 

----

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

 

***Interest Rate Risk —***PSCo is subject to the risk of fluctuatinginterest rates in the normal course of business.  PSCo’s risk management policy allows interestrate risk to be managed through the use of fixed rate debt, floating rate debtand interest rate derivatives such as swaps, caps, collars and put or calloptions, subject to regulatory approval when required.

 

PSComay engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges isinitially recorded in Other Comprehensive Income.  Reclassification of unrealized gains orlosses on cash flow hedges of variable rate debt instruments from OtherComprehensive Income into earnings occurs as interest payments are accrued onthe debt instrument and generally offsets the change in the interest accrued onthe underlying variable rate debt.  Thefair value of interest rate swaps is determined through counterpartyvaluations, internal valuations and broker quotes.  There have been no material changes in thetechniques or models used in the valuation of interest rate swaps during theperiods presented.

 

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

 

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

 

PSCo conducts standardcredit reviews for all counterparties. PSCo employs additional credit riskcontrol mechanisms when 

 

26

----

 

appropriate, such as lettersof credit, parental guarantees, standardized master netting agreements andtermination provisions that allow for offsetting of positive and negativeexposures. The credit exposure is monitored and, when necessary, the activitywith a specific counterparty is limited until credit enhancement is provided.

 

27

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**Item 8**— **FinancialStatements and Supple****mentary Data**

 

**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors andStockholderPublic Service Company of Colorado

 

We have audited theaccompanying consolidated balance sheets and consolidated statements ofcapitalization of Public Service Company of Colorado (a Colorado corporation)and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and therelated consolidated statements of income, stockholder’s equity andcomprehensive income (loss) and cash flows for each of the three years in theperiod ended December 31, 2004. Our audit also included the financial statementschedule listed in the Index at Item 15. These financial statements and financialstatement schedule are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements andfinancial statement schedules based on our audits.

 

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes consideration of internal control overfinancial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting. Accordingly, we express no such opinion. An audit also includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overallfinancial statement presentation. We believe that our audits provide areasonable basis for our opinion.

 

In our opinion, suchconsolidated financial statements present fairly, in all material respects, thefinancial position of Public Service Company of Colorado and its subsidiariesas of December 31, 2004 and 2003, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2004,in conformity with accounting principles generally accepted in the UnitedStates of America. Also, in our opinion, such financial statement schedule,when considered in relation to the basic consolidated financial statements takeas a whole, present fairly in all material respects the information set forththerein.

 

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

 

28

----

 

**PUBLIC SERVICE CO. OF COLORADO**

**CONSOLIDATED STATEMENTS OF INCOME**

 
| ** **                                                                                     | ** ** | **Year Ended Dec. 31,**    | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------------------------|------------|
| ** **                                                                                     | ** ** | **2004**                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                     | ** ** | **(Thousands of dollars)** | ** ** |
| Operating revenues:                                                                            |       |                       |       |   |   |   |   |
| Electric utility                                                                               |       | $                          | 2,194,628  |   | $ | 2,117,790 |   | $ | 1,878,193 |   |
| Natural gas utility                                                                            |       | 1,073,989                  |       | 883,052 |   | 749,355 |   |
| Steam and other                                                                                |       | 27,825                     |       | 23,271 |   | 24,365 |   |
| Total operating revenues                                                                       |       | 3,296,442                  |       | 3,024,113 |   | 2,651,913 |   |
|                                                                                           |       |                       |       |   |   |   |   |
| Operating expenses:                                                                            |       |                       |       |   |   |   |   |
| Electric fuel and purchased power                                                              |       | 1,242,684                  |       | 1,152,365 |   | 890,135 |   |
| Cost of natural gas sold and transported                                                       |       | 785,055                    |       | 578,108 |   | 422,442 |   |
| Cost of sales — steam and other                                                           |       | 17,383                     |       | 13,270 |   | 11,069 |   |
| Operating and maintenance expenses                                                             |       | 510,157                    |       | 496,119 |   | 463,389 |   |
| Depreciation and amortization                                                                  |       | 223,442                    |       | 226,785 |   | 247,598 |   |
| Taxes (other than income taxes)                                                                |       | 86,671                     |       | 83,386 |   | 77,042 |   |
| Total operating expenses                                                                       |       | 2,865,392                  |       | 2,550,033 |   | 2,111,675 |   |
|                                                                                           |       |                       |       |   |   |   |   |
| Operating income                                                                               |       | 431,050                    |       | 474,080 |   | 540,238 |   |
|                                                                                           |       |                       |       |   |   |   |   |
| Other income (expense):                                                                        |       |                       |       |   |   |   |   |
| Interest and other income, net of nonoperating expenses (see Note 9)                           |       | 24                         |       | (7,020 | ) | (4,641 | ) |
| Allowance for funds used during construction - equity                                          |       | 9,809                      |       | 8,380 |   | — |   |
| Total other income (expense)                                                                   |       | 9,833                      |       | 1,360 |   | (4,641 | ) |
|                                                                                           |       |                       |       |   |   |   |   |
| Interest charges and financing costs:                                                          |       |                       |       |   |   |   |   |
| Interest charges — including financing costs of $7,353, $7,822, and  $3,780, respectively |       | 157,447                    |       | 160,914 |   | 135,525 |   |
| Allowance for funds used during  construction - debt                                           |       | (7,425                     | )          | (8,990 | ) | (8,038 | ) |
| Distributions on redeemable preferred securities of subsidiary trust                           |       | —                     |       | 7,372 |   | 14,744 |   |
| Total interest charges and financing costs                                                     |       | 150,022                    |       | 159,296 |   | 142,231 |   |
|                                                                                           |       |                       |       |   |   |   |   |
| Income before income taxes                                                                     |       | 290,861                    |       | 316,144 |   | 393,366 |   |
| Income taxes                                                                                   |       | 72,856                     |       | 88,211 |   | 128,686 |   |
| Net income                                                                                     |       | $                          | 218,005    |   | $ | 227,933 |   | $ | 264,680 |   |

                

SeeNotes to Consolidated Financial Statements

 

29

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## ** **

## **PUBLIC SERVICE CO.OF COLORADO**

**CONSOLIDATED STATEMENTS OFCASH FLOWS**

 
| ** **                                                                                    | ** ** | **Year Ended Dec. 31,**    | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------------------------|------------|
| ** **                                                                                    | ** ** | **2004**                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                    | ** ** | **(Thousands of dollars)** | ** ** |
| Operating activities:                                                                         |       |                       |       |   |   |   |   |
| Net income                                                                                    |       | $                          | 218,005    |   | $ | 227,933 |   | $ | 264,680 |   |
| Adjustments to reconcile net income to cash provided by operating  activities:                |       |                       |       |   |   |   |   |
| Depreciation and amortization                                                                 |       | 234,164                    |       | 233,915 |   | 255,712 |   |
| Deferred income taxes                                                                         |       | 79,493                     |       | 86,748 |   | 108,721 |   |
| Amortization of investment tax credits                                                        |       | (4,000                     | )          | (6,531 | ) | (4,665 | ) |
| Allowance for equity funds used during construction                                           |       | (9,809                     | )          | (8,380 | ) | 24 |   |
| Change in accounts receivable                                                                 |       | (107,652                   | )          | (52,764 | ) | 24,763 |   |
| Change in accrued unbilled revenues                                                           |       | (17,819                    | )          | 48,934 |   | 65,198 |   |
| Change in inventories                                                                         |       | (31,781                    | )          | 6,703 |   | (18,091 | ) |
| Change in recoverable purchased natural gas and electric energy costs                         |       | (27,068                    | )          | (90,227 | ) | (74,077 | ) |
| Change in prepayments and other current assets                                                |       | (3,117                     | )          | (23,843 | ) | 8,881 |   |
| Change in accounts payable                                                                    |       | 22,894                     |       | 70,790 |   | (61,134 | ) |
| Change in other current liabilities                                                           |       | (5,222                     | )          | 48,166 |   | (56,697 | ) |
| Change in other noncurrent assets                                                             |       | 33,783                     |       | (18,299 | ) | (1,038 | ) |
| Change in other noncurrent liabilities                                                        |       | (44,812                    | )          | 12,438 |   | 969 |   |
| Net cash provided by operating activities                                                     |       | 337,059                    |       | 535,583 |   | 513,246 |   |
|                                                                                          |       |                       |       |   |   |   |   |
| Investing activities:                                                                         |       |                       |       |   |   |   |   |
| Capital/construction expenditures                                                             |       | (457,365                   | )          | (433,572 | ) | (443,176 | ) |
| Proceeds from disposition of property, plant and equipment                                    |       | 11,682                     |       | 4,375 |   | 17,322 |   |
| Allowance for equity funds used during construction                                           |       | 9,809                      |       | 8,380 |   | (24 | ) |
| Other investments                                                                             |       | (1,691                     | )          | (21,215 | ) | (2,207 | ) |
| Net cash used in investing activities                                                         |       | (437,565                   | )          | (442,032 | ) | (428,085 | ) |
|                                                                                          |       |                       |       |   |   |   |   |
| Financing activities:                                                                         |       |                       |       |   |   |   |   |
| Short-term borrowings — net                                                              |       | 182,914                    |       | (89,715 | ) | (488,161 | ) |
| Proceeds from issuance of long-term debt                                                      |       | —                     |       | 815,996 |   | 593,599 |   |
| Repayment of long-term debt and trust preferred securities, including  reacquisition premiums |       | (147,000                   | )          | (627,883 | ) | (18,674 | ) |
| Capital contribution from parent                                                              |       | 184,123                    |       | 145,496 |   | 62,200 |   |
| Dividends paid to parent                                                                      |       | (243,906                   | )          | (238,268 | ) | (230,867 | ) |
| Net cash provided by (used in) financing activities                                           |       | (23,869                    | )          | 5,626 |   | (81,903 | ) |
|                                                                                          |       |                       |       |   |   |   |   |
| Net increase (decrease) in cash and cash equivalents                                          |       | (124,375                   | )          | 99,177 |   | 3,258 |   |
| Cash and cash equivalents at beginning of year                                                |       | 125,101                    |       | 25,924 |   | 22,666 |   |
| Cash and cash equivalents at end of year                                                      |       | $                          | 726        |   | $ | 125,101 |   | $ | 25,924 |   |
|                                                                                          |       |                       |       |   |   |   |   |
| Supplemental disclosure of cash flow information:                                             |       |                       |       |   |   |   |   |
| Cash paid for interest (net of amounts capitalized)                                           |       | $                          | 151,424    |   | $ | 143,799 |   | $ | 112,179 |   |
| Cash paid for income taxes (net of refunds received)                                          |       | $                          | 16,203     |   | $ | (17,589 | ) | $ | 15,255 |   |

 

SeeNotes to Consolidated Financial Statements

 

30

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## **PUBLIC SERVICE CO.OF COLORADO**

**CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                                                                                | ** ** | **Dec. 31,  2004**         | ** ** | **Dec. 31,  2003** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------|------------|--------------------|------------|
| ** **                                                                                                                                | ** ** | **(Thousands of Dollars)** | ** ** |
| **ASSETS**                                                                                                                                |       |                       |       |               |       |
| Current assets:                                                                                                                           |       |                       |       |               |       |
| Cash and cash equivalents                                                                                                                 |       | $                          | 726        |               | $          | 125,101 |   |
| Accounts receivable – net of allowance for bad debts: $14,734 and  $12,852, respectively                                             |       | 341,946                    |       | 260,023            |       |
| Accounts receivable from affiliates                                                                                                       |       | 19,961                     |       | 6,409              |       |
| Accrued unbilled revenues                                                                                                                 |       | 172,854                    |       | 155,035            |       |
| Recoverable purchased natural gas and electric energy costs                                                                               |       | 172,215                    |       | 167,287            |       |
| Materials and supplies inventories – at average cost                                                                                 |       | 44,897                     |       | 41,301             |       |
| Fuel inventory – at average cost                                                                                                     |       | 23,533                     |       | 25,041             |       |
| Natural gas inventory – at average cost on Dec. 31, 2004; replacement  cost in excess of LIFO: $73,197 on Dec. 31, 2003 (see Note 1) |       | 149,985                    |       | 87,579             |       |
| Derivative instruments valuation-at market                                                                                                |       | 54,450                     |       | 51,007             |       |
| Prepayments and other                                                                                                                     |       | 73,896                     |       | 14,529             |       |
| Total current assets                                                                                                                      |       | 1,054,463                  |       | 933,312            |       |
|                                                                                                                                      |       |                       |       |               |       |
| Property, plant and equipment, at cost:                                                                                                   |       |                       |       |               |       |
| Electric utility plant                                                                                                                    |       | 6,123,791                  |       | 5,635,907          |       |
| Natural gas utility plant                                                                                                                 |       | 1,691,895                  |       | 1,556,740          |       |
| Construction work in progress                                                                                                             |       | 200,118                    |       | 468,241            |       |
| Other                                                                                                                                     |       | 786,025                    |       | 653,806            |       |
| Total property, plant and equipment                                                                                                       |       | 8,801,829                  |       | 8,314,694          |       |
| Less accumulated depreciation                                                                                                             |       | (2,862,494                 | )          | (2,725,507         | )          |
| Net property, plant and equipment                                                                                                         |       | 5,939,335                  |       | 5,589,187          |       |
|                                                                                                                                      |       |                       |       |               |       |
| Other assets:                                                                                                                             |       |                       |       |               |       |
| Other investments                                                                                                                         |       | 35,985                     |       | 33,998             |       |
| Regulatory assets                                                                                                                         |       | 246,564                    |       | 269,340            |       |
| Derivative instruments valuation-at market                                                                                                |       | 137,846                    |       | 200,990            |       |
| Deferred retail gas costs                                                                                                                 |       | —                     |       | 10,619             |       |
| Other                                                                                                                                     |       | 38,413                     |       | 36,415             |       |
| Total other assets                                                                                                                        |       | 458,808                    |       | 551,362            |       |
| Total assets                                                                                                                              |       | $                          | 7,452,606  |               | $          | 7,073,861 |   |
|                                                                                                                                      |       |                       |       |               |       |
| **LIABILITIES AND EQUITY**                                                                                                                |       |                       |       |               |       |
| Current liabilities:                                                                                                                      |       |                       |       |               |       |
| Current portion of long-term debt                                                                                                         |       | $                          | 135,854    |               | $          | 147,131 |   |
| Short-term debt                                                                                                                           |       | 186,300                    |       | 563                |       |
| Notes payable to affiliate                                                                                                                |       | 10,655                     |       | 12,938             |       |
| Accounts payable                                                                                                                          |       | 415,652                    |       | 369,974            |       |
| Accounts payable to affiliates                                                                                                            |       | 35,865                     |       | 59,132             |       |
| Taxes accrued                                                                                                                             |       | 72,446                     |       | 77,679             |       |
| Dividends payable to parent                                                                                                               |       | 62,565                     |       | 59,598             |       |
| Derivative instruments valuation-at market                                                                                                |       | 60,586                     |       | 55,845             |       |
| Accrued interest                                                                                                                          |       | 41,104                     |       | 47,974             |       |
| Other                                                                                                                                     |       | 87,294                     |       | 94,817             |       |
| Total current liabilities                                                                                                                 |       | 1,108,321                  |       | 925,651            |       |
|                                                                                                                                      |       |                       |       |               |       |
| Deferred credits and other liabilities:                                                                                                   |       |                       |       |               |       |
| Deferred income taxes                                                                                                                     |       | 744,326                    |       | 638,182            |       |
| Deferred investment tax credits                                                                                                           |       | 66,955                     |       | 70,955             |       |
| Regulatory liabilities                                                                                                                    |       | 475,136                    |       | 511,100            |       |
| Customers advances for construction                                                                                                       |       | 284,534                    |       | 191,800            |       |
| Minimum pension liability                                                                                                                 |       | 62,669                     |       | 54,647             |       |
| Derivative instruments valuation-at market                                                                                                |       | 157,130                    |       | 142,557            |       |
| Benefit obligations and other                                                                                                             |       | 87,022                     |       | 87,567             |       |
| Total deferred credits and other liabilities                                                                                              |       | 1,877,772                  |       | 1,696,808          |       |
|                                                                                                                                      |       |                       |       |               |       |
| Long-term debt                                                                                                                            |       | 2,179,961                  |       | 2,311,434          |       |
| Common stockholder’s equity:                                                                                                         |       |                       |       |               |       |
| Common stock – authorized 100 shares of $0.01 par value; outstanding  100 shares                                                     |       | —                     |       | —             |       |
| Premium on common stock                                                                                                                   |       | 1,981,903                  |       | 1,797,780          |       |
| Retained earnings                                                                                                                         |       | 392,746                    |       | 421,614            |       |
| Accumulated comprehensive loss                                                                                                            |       | (88,097                    | )          | (79,426            | )          |
| Total common stockholder’s equity                                                                                                    |       | 2,286,552                  |       | 2,139,968          |       |
| Commitments and contingencies (see Note 12)                                                                                               |       |                       |       |               |       |
| Total liabilities and equity                                                                                                              |       | $                          | 7,452,606  |               | $          | 7,073,861 |   |

 

SeeNotes to Consolidated Financial Statements

 

31

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## **PUBLIC SERVICE CO.OF COLORADO**

**CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY**

**AND OTHER COMPREHENSIVE INCOME (LOSS)**

 
| ** **                                                                             | ** ** | ** **                                           | ** ** | ** **     | ** ** | ** **       | ** ** | ** **        | ** ** | **Accumulated**        | ** ** | ** ** | ** ** |
|----------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|----------------|------------|------------------|------------|-------------------|------------|------------------------|------------|------------|------------|
| ** **                                                                             | ** ** | ** **                                           | ** ** | ** **     | ** ** | ** **       | ** ** | ** **        | ** ** | **Other**              | ** ** | **Total**  | ** ** |
| ** **                                                                             | ** ** | **Common Stock**                                     | ** ** | **Premium on** | ** ** | **Retained**     | ** ** | **Comprehensive** | ** ** | **Stockholder’s** | ** ** |
| ** **                                                                             | ** ** | **Shares**                                           | ** ** | **Amount**     | ** ** | **Common Stock** | ** ** | **Earnings**      | ** ** | **Income (Loss)**      | ** ** | **Equity** | ** ** |
| ** **                                                                             | ** ** | **(Thousands of dollars, except share information)** | ** ** |
|                                                                                   |       |                                                 |       |           |       |             |       |              |       |                   |       |       |       |
| Balance at Dec. 31, 2001                                                               |       | 100                                                  |       | $              | —     |             | $          | 1,590,084         |       | $                      | 404,347    |       | $          | (4,333 | ) | $ | 1,990,098 |   |
| Net income                                                                             |       |                                                 |       |           |       |             |       | 264,680           |       |                   |       | 264,680    |       |
| Minimum pension liability adjustment, net  of deferred tax of $64,600 (see Note 8)     |       |                                                 |       |           |       |             |       |              |       | (105,358               | )          | (105,358   | )          |
| Net derivative instrument fair value  changes during the period, net of tax of $3,256  |       |                                                 |       |           |       |             |       |              |       | 5,311                  |       | 5,311      |       |
| Unrealized loss — marketable securities,  net of tax of $76                       |       |                                                 |       |           |       |             |       |              |       | (439                   | )          | (439       | )          |
| Comprehensive income for 2002                                                          |       |                                                 |       |           |       |             |       |              |       |                   |       | 164,194    |       |
| Common dividends declared to parent                                                    |       |                                                 |       |           |       |             |       | (238,030          | )          |                   |       | (238,030   | )          |
| Contribution of capital by parent                                                      |       |                                                 |       |           |       | 62,200           |       |              |       |                   |       | 62,200     |       |
| Balance at Dec. 31, 2002                                                               |       | 100                                                  |       | $              | —     |             | $          | 1,652,284         |       | $                      | 430,997    |       | $          | (104,819 | ) | $ | 1,978,462 |   |
|                                                                                   |       |                                                 |       |           |       |             |       |              |       |                   |       |       |       |
| Net income                                                                             |       |                                                 |       |           |       |             |       | 227,933           |       |                   |       | 227,933    |       |
| Minimum pension liability adjustment, net  of deferred tax of $5,467 (see Note 8)      |       |                                                 |       |           |       |             |       |              |       | 8,917                  |       | 8,917      |       |
| Net derivative instrument fair value  changes during the period, net of tax of $10,753 |       |                                                 |       |           |       |             |       |              |       | 16,188                 |       | 16,188     |       |
| Unrealized gain — marketable securities,  net of tax of $176                      |       |                                                 |       |           |       |             |       |              |       | 288                    |       | 288        |       |
| Comprehensive income for 2003                                                          |       |                                                 |       |           |       |             |       |              |       |                   |       | 253,326    |       |
| Common dividends declared to parent                                                    |       |                                                 |       |           |       |             |       | (237,316          | )          |                   |       | (237,316   | )          |
| Contribution of capital by parent                                                      |       |                                                 |       |           |       | 145,496          |       |              |       |                   |       | 145,496    |       |
| Balance at Dec. 31, 2003                                                               |       | 100                                                  |       | $              | —     |             | $          | 1,797,780         |       | $                      | 421,614    |       | $          | (79,426 | ) | $ | 2,139,968 |   |
|                                                                                   |       |                                                 |       |           |       |             |       |              |       |                   |       |       |       |
| Net income                                                                             |       |                                                 |       |           |       |             |       | 218,005           |       |                   |       | 218,005    |       |
| Minimum pension liability adjustment, net  of deferred tax of $(4,202) (see Note 8)    |       |                                                 |       |           |       |             |       |              |       | (7,317                 | )          | (7,317     | )          |
| Net derivative instrument fair value  changes during the period, net of tax of $(947)  |       |                                                 |       |           |       |             |       |              |       | (1,475                 | )          | (1,475     | )          |
| Unrealized gain — marketable securities,  net of tax of $74                       |       |                                                 |       |           |       |             |       |              |       | 121                    |       | 121        |       |
| Comprehensive income for 2004                                                          |       |                                                 |       |           |       |             |       |              |       |                   |       | 209,334    |       |
| Common dividends declared to parent                                                    |       |                                                 |       |           |       |             |       | (246,873          | )          |                   |       | (246,873   | )          |
| Contribution of capital by parent                                                      |       |                                                 |       |           |       | 184,123          |       |              |       |                   |       | 184,123    |       |
| Balance at Dec. 31, 2004                                                               |       | 100                                                  |       | $              | —     |             | $          | 1,981,903         |       | $                      | 392,746    |       | $          | (88,097 | ) | $ | 2,286,552 |   |

 

SeeNotes to Consolidated Financial Statements

 

32

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## **PUBLIC SERVICE CO.OF COLORADO**

**CONSOLIDATED STATEMENTS OF CAPITALIZATION**

 
| ** **                                                                                             | ** ** | **Dec. 31,**                | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                             | ** ** | **2004**                    | ** ** | **2003** | ** ** |
| ** **                                                                                             | ** ** | **(Thousands of dollars )** | ** ** |
| **Long-Term Debt**                                                                                     |       |                        |       |   |   |
| First Mortgage Bonds, Series due:                                                                      |       |                        |       |   |   |
| March 1, 2004, 8.125%                                                                                  |       | $                           | —     |   | $ | 100,000 |   |
| Nov. 1, 2005, 6.375%                                                                                   |       | 134,500                     |       | 134,500 |   |
| June 1, 2006, 7.125%                                                                                   |       | 125,000                     |       | 125,000 |   |
| April 1, 2008, 5.625%                                                                                  |       | 18,000                      | (a)        | 18,000 | (a) |
| Oct. 1, 2008, 4.375%                                                                                   |       | 300,000                     |       | 300,000 |   |
| June 1, 2012, 5.5%                                                                                     |       | 50,000                      | (a)        | 50,000 | (a) |
| Oct. 1, 2012, 7.875%                                                                                   |       | 600,000                     |       | 600,000 |   |
| March 1, 2013, 4.875%                                                                                  |       | 250,000                     |       | 250,000 |   |
| April 1, 2014, 5.5%                                                                                    |       | 275,000                     |       | 275,000 |   |
| April 1, 2014, 5.875%                                                                                  |       | 61,500                      | (a)        | 61,500 | (a) |
| Jan. 1, 2019, 5.1%                                                                                     |       | 48,750                      | (a)        | 48,750 | (a) |
| Jan. 1, 2024, 7.25%                                                                                    |       | 110,000                     |       | 110,000 |   |
| Unsecured Senior A Notes, due July 15, 2009, 6.875%                                                    |       | 200,000                     |       | 200,000 |   |
| Secured Medium-Term Notes, due Feb. 2, 2004 - March 5, 2007, 6.9% -  7.11%                             |       | 100,000                     |       | 145,000 |   |
| Unamortized discount                                                                                   |       | (5,870                      | )          | (6,835 | ) |
| Capital lease obligations, 11.2% due in installments through 2028                                      |       | 48,935                      |       | 47,650 |   |
| Total                                                                                                  |       | 2,315,815                   |       | 2,458,565 |   |
| Less current maturities                                                                                |       | 135,854                     |       | 147,131 |   |
| Total PSCo long-term debt                                                                              |       | $                           | 2,179,961  |   | $ | 2,311,434 |   |
|                                                                                                   |       |                        |       |   |   |
| **Common Stockholder’s Equity**                                                                   |       |                        |       |   |   |
| Common stock — authorized 100 shares of $0.01 par value; outstanding  100 shares in 2004 and 2003 |       | $                           | —     |   | $ | — |   |
| Capital in excess of par value on common stock                                                         |       | 1,981,903                   |       | 1,797,780 |   |
| Retained earnings                                                                                      |       | 392,746                     |       | 421,614 |   |
| Accumulated other comprehensive income (loss)                                                          |       | (88,097                     | )          | (79,426 | ) |
| Total common stockholder’s equity                                                                 |       | $                           | 2,286,552  |   | $ | 2,139,968 |   |

 

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(a)      Pollution control financing.

 

SeeNotes to Consolidated Financial Statements

 

33

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**NOTES TOCONSOLIDATED****FINANCIAL STATEMENTS**

 

**1. Summaryof Significant Accounting Policies**

 

***Business and System of Accounts*****— PSCo is principally engaged in thegeneration, purchase, transmission, distribution and sale of electricity and inthe purchase, transportation, distribution and sale of natural gas. PSCo issubject to the regulatory provisions of the PUHCA and regulation by the FERCand state utility commissions. All of PSCo’s accounting records conform to theFERC uniform system of accounts or to systems required by various stateregulatory commissions, which are the same in all material aspects.

 

***Principles of Consolidation*****— PSCo has subsidiaries, which have beenconsolidated and for which all significant intercompany transactions andbalances have been eliminated.

 

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

 

PSCo has various rateadjustment mechanisms in place that currently provide for the recovery ofcertain purchased natural gas and electric energy costs. These cost adjustmenttariffs may increase or decrease the level of costs recovered through baserates and are revised periodically, as prescribed by the appropriate regulatoryagencies, for any difference between the total amount collected under the clausesand the recoverable costs incurred. In addition, PSCo presents their revenue,net of any excise or other fiduciary-type taxes or fees. A summary ofsignificant rate adjustment mechanisms follows:

 

•                  In 2004, PSCogenerally recovered all prudently incurred electric fuel and purchased energycosts through an electric commodity adjustment clause.  This fuel mechanism also has in place asharing among customers and shareholders of certain fuel and energy costs, withan $11.25 million maximum on any cost sharing over or under an allowed electriccommodity adjustment formula rate and a sharing among shareholders andcustomers of certain gains and losses on trading margins.  In 2003, PSCo’s electric rates permittedrecovery of 100 percent of prudently incurred electric fuel and purchasedenergy expense. In 2002, PSCo’s electric rates in Colorado were adjusted underan incentive cost-adjustment mechanism, which resulted in the sharing of costincreases and decreases with customers and sharing of trading margins.

 

•                  In Colorado, PSCo operates under an electricperformance-based regulatory plan, which provides for an annual earnings test.PSCo operates under various service standards, which could require customerrefunds if certain criteria are not met. PSCo’s rates include monthlyadjustments for the recovery of conservation and energy management programcosts, which are reviewed annually.

 

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

 

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

 

Pursuant to the JOA approvedby the FERC, some of the commodity trading margins from PSCo are apportioned toNSP-Minnesota and SPS. Commodity trading activities are not associated withenergy produced from PSCo’s generation assets or energy and capacity purchasedto serve native load. Commodity trading results are recorded at fair market valuein accordance with SFAS 133, as amended. In addition, commodity-trading resultsinclude the impacts of any margin-sharing mechanisms. For more information, seeNote 10 to the Consolidated Financial Statements.

 

***Derivative Financial Instruments****—*PSCo utilizes a variety of derivatives,including interest rate swaps and locks and physical and financial basedcommodity 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’srisk management and derivative activities see Note 10 to the ConsolidatedFinancial Statements.

 

***Property, Plant, Equipment and Depreciation*****— Property, plant and equipment is stated atoriginal cost. The cost of plant includes direct labor and materials,contracted work, overhead costs and applicable interest expense. The cost ofplant retired is charged to accumulated depreciation and amortization. Removalcosts

 

34

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associated with non-legalobligations are reclassified from accumulated depreciation and reflected asregulatory liabilities. Significant additions or improvements extending assetlives are capitalized, while repairs and maintenance are charged to expense asincurred. Maintenance and replacement of items determined to be less than unitsof property are charged to operating expenses. Property, plant and equipmentalso include costs associated with the engineering design of future generatingstations and other property held for future use.

 

PSCo determines thedepreciation of their plant by using the straight-line method, which spreadsthe original cost equally over the plant’s useful life. Depreciation expensefor PSCo, expressed as a percentage of average depreciable property, for theyears ended Dec. 31, 2004, 2003 and 2002 is 2.5 percent, 2.5 percent and 2.5percent, respectively.

 

***Allowance for Funds Used During Construction (AFDC)*****— AFDC represents the cost of capital used tofinance utility construction activity. AFDC is computed by applying a compositepretax rate to qualified construction work in progress. The amount of AFDCcapitalized as a utility construction cost is credited to other income anddeductions (for equity capital) and interest charges (for debt capital). AFDCamounts capitalized are included in PSCo’s rate base for establishing utilityservice rates.

 

***Decommissioning*****—PSCo previously operated a nuclear generating plant, which has beendecommissioned and repowered using natural gas. PSCo’s costs associated withdecommissioning were deferred and are being amortized consistent with the CPUCregulatory recovery.

 

***Environmental Costs*****—Environmental costs are recorded when it is probable PSCo is liable for thecosts and the liability can be reasonably estimated. Costs may be deferred as aregulatory asset based on an expectation that the costs will be recovered fromcustomers in future rates. Otherwise, the costs are expensed. If anenvironmental expense is related to facilities currently in use, such aspollution-control equipment, the cost is capitalized and depreciated over thelife of the plant, assuming the costs are recoverable in future rates or futurecash flow.

 

Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based onexperience, an assessment of the current situation and the technology currentlyavailable for use in the remediation. The recorded costs are regularly adjustedas estimates are revised and remediation proceeds. If several designatedresponsible parties exist, costs are estimated and recorded only for theutility subsidiary share of the cost. Any future costs of restoring sites whereoperation may extend indefinitely are treated as a capitalized cost of plantretirement. The depreciation expense levels recoverable in rates include aprovision for removal expenses, which has the latitude to compensate for finalremediation costs.  Removal costsrecovered in rates are classified as a regulatory liability.

 

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

 

***Income Taxes*****—Xcel Energy and its utility subsidiaries, including PSCo, file consolidatedfederal and combined and separate state income tax returns. Income taxes forconsolidated or combined subsidiaries are allocated to the subsidiaries basedon separate company computations of taxable income or loss. In accordance withthe PUHCA requirements, the holding company also allocates its own net incometax benefits to its direct subsidiaries based on the positive tax liability ofeach company in the consolidated federal or combined state returns. PSCo defersincome taxes for all temporary differences between the book and tax bases ofassets and liabilities. The tax rates used are those that are scheduled to bein effect when the temporary differences are expected to turn around, orreverse.

 

Due to the effects of pastregulatory practices, when deferred taxes were not required to be recorded, thereversal of some temporary differences was accounted for as current income taxexpense. Investment tax credits are deferred and their benefits spread over theestimated lives of the related property. Utility rate regulation also hascreated certain regulatory assets and liabilities related to income taxes,which are summarized in Note 13 to the Consolidated Financial Statements. Formore information on income taxes, see Note 7 to the Consolidated FinancialStatements.

 

***Use of Estimates*****—In recording transactions and balances resulting from business operations, PSCouses estimates based on the best information available. Estimates are used forsuch items as plant depreciable lives, tax provisions, uncollectible amounts,environmental costs, unbilled revenues, jurisdictional fuel and energy costallocations and actuarially determined benefit costs. The recorded estimatesare revised when better information is obtained or actual amounts aredeterminable. Those revisions can affect operating results. Each year thedepreciable lives of certain plant assets are reviewed and revised, ifappropriate.

 

35

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***Cash and Cash Equivalents*****— PSCo considers investments with a remainingmaturity of three months or less at the time of purchase to be cashequivalents. Those instruments are primarily commercial paper and money marketfunds.

 

***Inventory*****— Allinventories are recorded at average cost in 2004.   Effective Jan. 1, 2004, PSCo changed itsmethod of accounting for the cost of stored natural gas for its localdistribution operations from the last-in-first-out (LIFO) pricing method to theaverage cost pricing method. This change in accounting was approved by the CPUCand was accounted for as a cumulative effect in accordance with the CPUCauthorization. The average cost method has historically been used  by PSCo for natural gas stored for use in itselectric utility operations.

 

The cumulativeeffect of this change in accounting principle resulted in an increase tonatural gas storage inventory and a corresponding decrease to the deferrednatural gas cost accounts of approximately $36 million as of Jan. 1, 2004. Ofthis amount, $33 million related to current natural gas storage inventory and$3 million related to long-term natural gas storage inventory. As natural gascosts are 100 percent recoverable for PSCo’s local natural gas distributionoperations under PSCo’s natural gas cost adjustment mechanism, the cumulativeeffect of this change had no impact on net income. Prior period financialstatements were not restated since the CPUC authorized this change effectiveJan. 1, 2004. Under the natural gas cost adjustment mechanism, the decrease inthe cost of natural gas reduced rates to retail natural gas customers inColorado during 2004.

 

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

 

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

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

 

Estimates of recoveringdeferred costs and returning deferred credits are based on specific ratemakingdecisions or precedent for each item. Regulatory assets and liabilities areamortized consistent with the period of expected regulatory treatment.

 

If restructuring or otherchanges in the regulatory environment occur, PSCo may no longer be eligible toapply this accounting treatment, and may be required to eliminate suchregulatory assets and liabilities from its balance sheet.  Such changes could have a material effect onPSCo’s results of operations in the period the write-off is recorded.  See more discussion of regulatory assets andliabilities at Note 13 to the Consolidated Financial Statements.

 

***Deferred Financing Costs*****— Other assets include deferred financingcosts, which were amortized over the remaining maturity periods of the relateddebt. PSCo’s deferred financing costs, net of amortization at Dec. 31, 2004,2003 and 2002 are $15.1 million,  $17.2million, and $18.9 million, respectively.

 

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

 

**2.****    ****Short-Term Borrowings**

** **

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

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

 

PSCo’s credit facility isexpected to be renewed as a five-year revolving credit facility prior to May2005 for which borrowings will be classified as a long-term liability on theconsolidated balance sheet.

 

The line of credit providesshort-term financing in the form of notes payable to banks, letters of credit,and, depending on credit ratings, provide support for commercial paperborrowings. The borrowing rate under the line of credit is based on either thebank’s prime rate or the applicable London Interbank Offered Rate (LIBOR) plusa borrowing margin.

 

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

 

36

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Also, as discussed in Note11 to the Consolidated Financial Statements, $11.3 million of letters of creditwere outstanding at Dec. 31, 2004 under the credit facility, which furtherreduced amounts available under the line.

 

***Money Pool -***In 2003, Xcel Energyestablished a money pool arrangement with the utility subsidiaries, subject toreceipt of required state regulatory approvals. PSCo received approval to participate in the money pool arrangement in2004.  The money pool allows forshort-term loans between the utility subsidiaries and from the holding companyto the utility subsidiaries at market-based interest rates. The money pool arrangementdoes not allow loans from the utility subsidiaries to the holding company.  PSCo has approval to borrow up to $250million under the arrangement.  PSCo hadno borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

 

**3.****    ****Long-Term Debt**

** **

Except for minor exclusions,all property of PSCo is subject to a first mortgage lien of its 1939 firstmortgage indenture.  All of PSCo’selectric property is subject to the lien of its 1993 first collateral trustindenture and such lien is junior to the lien of the 1939 first mortgageindenture.  Both indentures are contractsbetween PSCo and its bondholders.

 

PSCo’s indentures providefor the ability to have sinking fund requirements. Such sinking fundobligations may be satisfied with property additions or cash. At Dec. 31, 2004,PSCo has no sinking fund requirements for current bonds outstanding.

 

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

 

Maturities of long-term debtfor the utility subsidiaries are listed in the following table, in millions ofdollars:

 
| 2005 |   | $   | 136    |   |
|------|--------|-----|--------|--------|
| 2006 |   | 126 |   |
| 2007 |   | 101 |   |
| 2008 |   | 319 |   |
| 2009 |   | 202 |   |

 

**4.Preferred Stock**

 

PSCo has authorized theissue of preferred shares.

 
| **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, awholly owned, special-purpose subsidiary trust of PSCo, had $194 million of7.60-percent trust preferred securities issued and outstanding that wereoriginally scheduled to mature in 2038. The securities were redeemable at the option of PSCo after May 2003, at100 percent of the principal amount outstanding plus accrued interest. On June30, 2003, PSCo redeemed the $194 million of trust preferred securities. Acertificate of cancellation was filed to dissolve PSCo Capital Trust I on Dec.29, 2003.

 

Distributions paid topreferred security holders are reflected as a financing cost in theaccompanying Consolidated Statements of Income along with interest expense.

 

**6. JointPlant Ownership**

 

Following are theinvestments by PSCo in jointly owned plants and the related ownershippercentages as of Dec. 31, 2004:

 

37

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| ** **                                               | ** ** | **Plant in  Service**      | ** ** | **Accumulated   Depreciation** | ** ** | **Construction   Work in  Progress** | ** ** | **Ownership %** | ** ** |
|----------------------------------------------------------|------------|----------------------------|------------|--------------------------------|------------|--------------------------------------|------------|----------------------|------------|
| ** **                                               | ** ** | **(Thousands of dollars)** | ** ** |
|                                                     |       |                       |       |                           |       |                                 |       |                 |       |
| Hayden Unit 1                                            |       | $                          | 85,638     |                           | $          | 42,839                               |       | $                    | —     |   | 75.5 |   |
| Hayden Unit 2                                            |       | 79,979                     |       | 45,094                         |       | 443                                  |       | 37.4                 |       |
| Hayden Common Facilities                                 |       | 28,600                     |       | 4,815                          |       | 16                                   |       | 53.1                 |       |
| Craig Units 1 and 2                                      |       | 58,604                     |       | 31,698                         |       | 33                                   |       | 9.7                  |       |
| Craig Common Facilities, Unit1, 2 and 3                  |       | 32,553                     |       | 9,547                          |       | 18                                   |       | 6.5  – 9.7      |       |
| Transmission and other facilities, including substations |       | 150,812                    |       | 41,171                         |       | 359                                  |       | 11.6  – 73.0    |       |
| Total PSCo                                               |       | $                          | 436,186    |                           | $          | 175,164                              |       | $                    | 869        |   |   |   |

 

PSCo’s assets includeapproximately 320 megawatts of jointly owned generating capacity. PSCo’s shareof operating expenses and construction expenditures are included in theapplicable utility components of operating expenses. PSCo is responsible forthe issuance of its own securities to finance its portion of the constructioncosts.

 

**7.****    ****Income Taxes**

 

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

 
| ** **                                            | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                  |       |     |       |     |       |     |       |
| Federal statutory rate                                |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases (decreases) in tax from:                    |       |     |       |     |       |     |       |
| State income taxes, net of federal income tax benefit |       | 3.4      | %          | 2.9      | %          | 2.7      | %          |
| Life insurance policies                               |       | (9.4     | )%         | (8.1     | )%         | (6.2     | )%         |
| Tax credits recognized                                |       | (2.1     | )%         | (2.1     | )%         | (3.0     | )%         |
| Regulatory differences —utility plant items      |       | 1.5      | %          | 2.5      | %          | 2.6      | %          |
| Resolution of income tax audits                       |       | (4.9     | )%         | (2.9     | )%         | —   |       |
| Other — net                                      |       | 1.5      | %          | 0.6      | %          | 1.6      | %          |
| Effective income tax rate                             |       | 25.0     | %          | 27.9     | %          | 32.7     | %          |

 

Income taxes comprise thefollowing expense (benefit) items:

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

 

The components of deferredincome tax at Dec. 31 were:

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

 

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

 

38

----

 
| ** **                                         | ** ** | **2004**                   | ** ** | **2003** | ** ** |
|----------------------------------------------------|------------|----------------------------|------------|----------|------------|
| ** **                                         | ** ** | **(Thousands of dollars)** | ** ** |
| Deferred tax liabilities:                          |       |                       |       |     |       |
| Differences between book and tax basis of property |       | $                          | 792,103    |     | $          | 629,653 |   |
| Regulatory assets                                  |       | 44,249                     |       | 40,861   |       |
| Deferred costs                                     |       | 46,006                     |       | 74,898   |       |
| Employee benefits                                  |       | 19,881                     |       | 56,181   |       |
| Other                                              |       | 4,002                      |       | 26,345   |       |
| Total deferred tax liabilities                     |       | $                          | 906,241    |     | $          | 827,938 |   |
|                                               |       |                       |       |     |       |
| Deferred tax assets:                               |       |                       |       |     |       |
| Unbilled revenue                                   |       | $                          | 57,273     |     | $          | 56,010 |   |
| Other comprehensive income                         |       |                       | 53,776     |     |       | 48,760 |   |
| Net operating loss carryforward                    |       | 32,298                     |       | 11,144   |       |
| Deferred investment tax credits                    |       | 25,250                     |       | 26,968   |       |
| Regulatory liabilities                             |       | 12,852                     |       | 16,447   |       |
| Other                                              |       | 21,945                     |       | 954      |       |
| Total deferred tax assets                          |       | $                          | 203,394    |     | $          | 160,283 |   |
| Net deferred tax liability                         |       | $                          | 702,847    |     | $          | 667,656 |   |

** **

**8. BenefitPlans and Other Postretirement Benefits**

 

Xcel Energy offers variousbenefit plans to its benefit employees, including those of PSCo. Approximately51 percent of benefit employees are represented by several local labor unionsunder several collective-bargaining agreements. At Dec. 31, 2004, PSCo had2,177 bargaining employees covered under a collective-bargaining agreement,which expires in May 2006.

 

**PensionBenefits**

 

Xcel Energy has severalnoncontributory, defined benefit pension plans that cover almost all employees,including those of PSCo.  Benefits arebased on a combination of years of service, the employee’s average pay andSocial Security benefits.

 

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

 

***Pension Plan Assets***— Plan assets principally consist of the common stock of publiccompanies, corporate bonds and U.S. government securities. In 2004, Xcel Energycompleted a review of its pension plan asset allocation and adopted revisedasset allocation targets.  The targetrange for our pension asset allocation is 60 percent in equity investments, 20percent in fixed income investments, no cash investments and 20 percent innontraditional investments, such as real estate, timber ventures, privateequity and a diversified commodities index.

 

The actual composition ofpension plan assets at Dec. 31 was:

 
| ** **                 | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------|------------|----------|------------|----------|------------|
|                       |       |     |       |     |       |
| Equity securities          |       | 69       | %          | 75       | %          |
| Debt securities            |       | 19       |       | 14       |       |
| Real estate                |       | 4        |       | 3        |       |
| Cash                       |       | 1        |       | —   |       |
| Nontraditional investments |       | 7        |       | 8        |       |
|                       |       | 100      | %          | 100      | %          |

 

During 2003, Xcel Energyentered into a number of hedging arrangements within the pension trust designedto provide protection from a loss of asset value in the event of a broaddecline in equity prices. These arrangements were closed out in December 2004.

 

Xcel Energy bases itsinvestment return assumption on expected long-term performance for each of theinvestment types included in its pension asset portfolio. Xcel Energy considersthe actual historical returns achieved by its asset portfolio over the past20-year or longer period, as well as the long-term return levels projected andrecommended by investment experts. The historical weighted average annualreturn for the past 20 years for the Xcel Energy portfolio of pensioninvestments is 12.8 percent, which is greater than the current assumptionlevel. The pension cost determinations assume the continued current mix ofinvestment types over the long-term. The Xcel Energy portfolio is heavilyweighted toward equity securities and includes nontraditional investments thatcan provide a higher-than-average return. As is the experience in recent years,a higher weighting in equity investments can increase the volatility in thereturn levels actually achieved by pension assets in any year. Investmentreturns in 2002 were below the assumed level of 9.5 percent, but in 2003investment returns exceeded the assumed level of 9.25 percent and in 2004investment returns exceeded the 

 

39

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

 

***Benefit Obligations***— A comparison of the actuarially computed pension benefit obligationand plan assets, on a combined basis, is presented in the following table:

 

 
| **(Thousands of dollars)**                                             | ** ** | **2004**       | ** ** | **2003**       | ** ** |
|------------------------------------------------------------------------|------------|----------------|------------|----------------|------------|
|                                                                   |       |           |       |           |       |
| **Accumulated Benefit Obligation at Dec. 31**                          |       | $              | 2,575,317  |           | $          | 2,512,138 |   |
|                                                                   |       |           |       |           |       |
| **Change in Projected Benefit Obligation**                             |       |           |       |           |       |
| Obligation at Jan. 1                                                   |       | $              | 2,632,491  |           | $          | 2,505,576 |   |
| Service cost                                                           |       | 58,150         |       | 67,449         |       |
| Interest cost                                                          |       | 165,361        |       | 170,731        |       |
| Plan amendments                                                        |       | —         |       | 85,937         |       |
| Actuarial loss                                                         |       | 133,552        |       | 82,197         |       |
| Settlements                                                            |       | (27,627        | )          | (9,546         | )          |
| Curtailment gain                                                       |       | —         |       | (26,407        | )          |
| Benefit payments                                                       |       | (229,664       | )          | (243,446       | )          |
| Obligation at Dec. 31                                                  |       | $              | 2,732,263  |           | $          | 2,632,491 |   |
|                                                                   |       |           |       |           |       |
| **Change in Fair Value of Plan Assets**                                |       |           |       |           |       |
| Fair value of plan assets at Jan. 1                                    |       | $              | 3,024,661  |           | $          | 2,639,963 |   |
| Actual return on plan assets                                           |       | 284,600        |       | 605,978        |       |
| Employer contributions                                                 |       | 10,046         |       | 31,712         |       |
| Settlements                                                            |       | (27,627        | )          | (9,546         | )          |
| Benefit payments                                                       |       | (229,664       | )          | (243,446       | )          |
| Fair value of plan assets at Dec. 31                                   |       | $              | 3,062,016  |           | $          | 3,024,661 |   |
|                                                                   |       |           |       |           |       |
| **Funded Status of Plans at Dec. 31**                                  |       |           |       |           |       |
| Net asset                                                              |       | $              | 329,753    |           | $          | 392,170 |   |
| Unrecognized transition asset                                          |       | —         |       | (7             | )          |
| Unrecognized prior service cost                                        |       | 244,437        |       | 273,725        |       |
| Unrecognized loss                                                      |       | 176,957        |       | 9,710          |       |
| Xcel Energy net pension amounts recognized on balance sheet            |       | $              | 751,147    |           | $          | 675,598 |   |
|                                                                   |       |           |       |           |       |
| PSCo intangible asset recorded — prior service costs              |       | $              | 4,594      |           | $          | 5,724 |   |
| PSCo accrued benefit liability recorded                                |       | (4,193         | )          | (3,096         | )          |
| PSCo minimum pension liability recorded                                |       | (62,669        | )          | (54,647        | )          |
| PSCo accumulated other comprehensive income recorded – pretax     |       | 167,093        |       | 155,574        |       |
| PSCo accumulated other comprehensive income recorded – net of tax |       | 103,758        |       | 96,441         |       |
|                                                                   |       |           |       |           |       |
| **Measurement Date**                                                   |       | Dec.  31, 2004 |       | Dec.  31, 2003 |       |
|                                                                   |       |           |       |           |       |
| **Significant Assumptions Used to Measure Benefit  Obligations**       |       |           |       |           |       |
| Discount rate for year-end valuation                                   |       | 6.00           | %          | 6.25           | %          |
| Expected average long-term increase in compensation level              |       | 3.50           | %          | 3.50           | %          |

 

During 2002, one of PSCo’s pensionplans became under funded, and at Dec. 31, 2004, had projected benefitobligations of $694.4 million, exceeding plan assets of $590.1 million. PSCohas recorded a minimum pension liability of $62.7 million related to the underfunded plan as of that date. A corresponding reduction in Accumulated OtherComprehensive Income, a component of Stockholders’ Equity, also was recorded,as previously recorded prepaid pension assets were reduced to record theminimum liability. Net of the related deferred income tax effects of theadjustments, total PSCo Stockholder’s Equity was reduced by $103.8 million atDec. 31, 2004, due to the minimum pension liability for the under funded plan.All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion andprojected benefit obligations of $2.0 billion on Dec. 31, 2004.

 

40

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***Cash Flows***—Cash funding requirements can be impacted by changes to actuarial assumptions,actual asset levels and other pertinent calculations prescribed by the fundingrequirements of income tax and other pension-related regulations. Theseregulations did not require cash funding in the years 2002 through 2004 forXcel Energy’s pension plans and is not expected to require cash funding in2005. PSCo elected to make a voluntary contribution of $30 million to itspension plan for bargaining employees in 2003 and $9 million in 2004.

 

***Benefit Costs***—******Thecomponents of net periodic pension cost (credit) are:

 
| **(Thousands of dollars)**                                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                      |       |     |       |     |       |     |       |
| Service cost                                              |       | $        | 58,150     |     | $          | 67,449   |       | $ | 65,649 |   |
| Interest cost                                             |       | 165,361  |       | 170,731  |       | 172,377  |       |
| Expected return on plan assets                            |       | (302,958 | )          | (322,011 | )          | (339,932 | )          |
| Curtailment (gain) loss                                   |       | —   |       | (17,363  | )          | —   |       |
| Settlement (gain) loss                                    |       | (926     | )          | (1,135   | )          | —   |       |
| Amortization of transition asset                          |       | (7       | )          | (1,996   | )          | (7,314   | )          |
| Amortization of prior service cost                        |       | 30,009   |       | 28,230   |       | 22,663   |       |
| Amortization of net gain                                  |       | (15,207  | )          | (44,825  | )          | (69,264  | )          |
| Net periodic pension credit under SFAS No. 87             |       | $        | (65,578    | )        | $          | (120,920 | )          | $ | (155,821 | ) |
|                                                      |       |     |       |     |       |     |       |
| **PSCo**                                                  |       |     |       |     |       |     |       |
| Net periodic pension cost (credit)                        |       | $        | 7,141      |     | $          | (4,728   | )          | $ | (14,747 | ) |
|                                                      |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs**         |       |     |       |     |       |     |       |
| Discount rate                                             |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected average long-term increase in compensation level |       | 3.50     | %          | 4.00     | %          | 4.50     | %          |
| Expected average long-term rate of return on assets       |       | 9.00     | %          | 9.25     | %          | 9.50     | %          |

 

Pension costs include anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2005 pensioncost calculations will be 8.75 percent. The cost calculation uses amarket-related valuation of pension assets, which reduces year-to-yearvolatility by recognizing the differences between assumed and actual investmentreturns over a five-year period.

 

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

 

**DefinedContribution Plans**

 

Xcel Energy maintains 401(k)and other defined contribution plans that cover substantially all employees.The contributions for PSCo  wereapproximately $7.2 million in 2004, $4.7 million in 2003 and $5.9 million in2002.

 

**PostretirementHealth Care Benefits**

 

Xcel Energy has acontributory health and welfare benefit plan that provides health care anddeath benefits to most Xcel Energy retirees. Employees of the former NCE whoretired in 2002 continue to receive employer-subsidized health care benefits.

 

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

 

Regulatory agencies fornearly all of Xcel Energy’s retail and wholesale utility customers have allowedrate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned tofull accrual accounting for SFAS No. 106 costs between 1993 and 1997,consistent with the accounting requirements for rate-regulated enterprises. TheColorado jurisdictional SFAS No. 106 costs deferred during the transitionperiod are being amortized to expense on a straight-line basis over the 15-yearperiod from 1998 to 2012.

 

41

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***Plan Assets***—Certain state agencies that regulate Xcel Energy’s utility subsidiaries alsohave issued guidelines related to the funding of SFAS No. 106 costs. PSCo isrequired to fund SFAS No. 106 costs in irrevocable external trusts that arededicated to the payment of these postretirement benefits. In 2004, theinvestment strategy for the union asset fund was changed to increase theexposure to equity funds. Also, a portion of the assets contributed on behalfof non-bargaining retirees has been funded into a sub-account of the XcelEnergy pension plans. These assets are invested in a manner consistent with theinvestment strategy for the pension plan.

 

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

 
| ** **                               | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
|                                     |       |     |       |     |       |
| Fixed income/debt securities             |       | 21       | %          | 2        | %          |
| Equity and equity mutual fund securities |       | 54       |       | 14       |       |
| Cash equivalents                         |       | 25       |       | 84       |       |
|                                     |       | 100      | %          | 100      | %          |

 

Xcel Energy bases itsinvestment return assumption for the postretirement health care fund assets onexpected long-term performance for each of the investment types included in itspostretirement health care asset portfolio. Given the fairly short time periodin which funding has been required, Xcel Energy does not consider the actualhistorical returns achieved by its postretirement health care fund assetportfolio to be significant in establishing long-term return assumptions.Instead, Xcel Energy considers the long-term return levels projected andrecommended by investment experts, weighted for the target mix of assetcategories in our portfolio and does not consider investment return volatilityto be a material factor in postretirement health care costs.

 

***Benefit Obligations***— A comparison of the actuarially computed benefit obligation and planassets for Xcel Energy postretirement health care plans that benefit employeesof its utility subsidiaries is presented in the following table:

 

 
| **(Thousands of dollars)**                                                       | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
|                                                                             |       |     |       |     |       |
| **Change in Benefit Obligation**                                                 |       |     |       |     |       |
| Obligation at Jan. 1                                                             |       | $        | 775,230    |     | $          | 767,975 |   |
| Service cost                                                                     |       | 6,100    |       | 5,893    |       |
| Interest cost                                                                    |       | 52,604   |       | 52,426   |       |
| Acquisitions/(divestitures)                                                      |       | —   |       | (31,584  | )          |
| Plan amendments                                                                  |       | (1,600   | )          | (33,304  | )          |
| Plan participants’ contributions                                            |       | 9,532    |       | 16,577   |       |
| Actuarial loss                                                                   |       | 148,341  |       | 122,864  |       |
| Curtailments                                                                     |       | —   |       | (249     | )          |
| Benefit payments                                                                 |       | (61,082  | )          | (60,754  | )          |
| Impact of Medicare Prescription Drug, Improvement and Modernization  Act of 2003 |       | —   |       | (64,614  | )          |
| Obligation at Dec. 31                                                            |       | $        | 929,125    |     | $          | 775,230 |   |
|                                                                             |       |     |       |     |       |
| **Change in Fair Value of Plan Assets**                                          |       |     |       |     |       |
| Fair value of plan assets at Jan. 1                                              |       | $        | 285,861    |     | $          | 250,983 |   |
| Actual return on plan assets                                                     |       | 21,950   |       | 11,045   |       |
| Plan participants’ contributions                                            |       | 9,532    |       | 16,577   |       |
| Employer contributions                                                           |       | 62,406   |       | 68,010   |       |
| Benefit payments                                                                 |       | (61,082  | )          | (60,754  | )          |
| Fair value of plan assets at Dec. 31                                             |       | $        | 318,667    |     | $          | 285,861 |   |
|                                                                             |       |     |       |     |       |
| **Funded Status at Dec. 31**                                                     |       |     |       |     |       |
| Net obligation                                                                   |       | $        | 610,458    |     | $          | 489,369 |   |
| Unrecognized transition asset (obligation)                                       |       | (117,600 | )          | (133,778 | )          |
| Unrecognized prior service cost                                                  |       | 17,914   |       | 20,093   |       |
| Unrecognized gain (loss)                                                         |       | (383,026 | )          | (255,174 | )          |
| Accrued benefit liability recorded                                               |       | $        | 127,746    |     | $          | 120,510 |   |
|                                                                             |       |     |       |     |       |
| PSCo accrued benefit liability recorded                                          |       | $        | 44,620     |     | $          | 44,455 |   |
|                                                                             |       |     |       |     |       |
| **Significant Assumptions Used to Measure Benefit  Obligations**                 |       |     |       |     |       |
| Discount rate for year-end valuation                                             |       | 6.00     | %          | 6.25     | %          |

 

42

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

 

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

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

 

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

 

***Cash Flows***—The postretirement health care plans have no funding requirements under incometax and other retirement-related regulations other than fulfilling benefitpayment obligations, when claims are presented and approved under the plans.Additional cash funding requirements are prescribed by certain state andfederal rate regulatory authorities, as discussed previously. Xcel Energy expectsto contribute approximately $73 million during 2005.

 

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

 
| **(Thousands of dollars)**                                              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                                    |       |     |       |     |       |     |       |
| Service cost                                                            |       | $        | 6,100      |     | $          | 5,893    |       | $ | 5,967 |   |
| Interest cost                                                           |       | 52,604   |       | 52,426   |       | 48,304   |       |
| Expected return on plan assets                                          |       | (23,066  | )          | (22,185  | )          | (21,011  | )          |
| Curtailment (gain) loss                                                 |       | —   |       | (2,128   | )          | —   |       |
| Settlement (gain) loss                                                  |       | —   |       | (916     | )          | —   |       |
| Amortization of transition obligation                                   |       | 14,578   |       | 15,426   |       | 16,771   |       |
| Amortization of prior service cost (credit)                             |       | (2,179   | )          | (1,533   | )          | (1,130   | )          |
| Amortization of net loss (gain)                                         |       | 21,651   |       | 15,409   |       | 5,380    |       |
| Net periodic postretirement benefit cost (credit) under SFAS No. 106    |       | 69,688   |       | 62,392   |       | 54,281   |       |
|                                                                    |       |     |       |     |       |     |       |
| **PSCo**                                                                |       |     |       |     |       |     |       |
| Net periodic postretirement benefit cost recognized – SFAS No. 106 |       | 42,248   |       | 37,146   |       | 30,619   |       |
| Additional cost recognized due to effects of regulation                 |       | 3,891    |       | 3,883    |       | 3,890    |       |
| Net cost recognized for financial reporting                             |       | $        | 46,139     |     | $          | 41,029   |       | $ | 34,509 |   |
|                                                                    |       |     |       |     |       |     |       |
| **Significant assumptions used to measure costs  (income)**             |       |     |       |     |       |     |       |
| Discount rate                                                           |       | 6.25     | %          | 6.75     | %          | 7.25     | %          |
| Expected average long-term rate of return on assets (before tax)        |       | 5.5%-8.5 | %          | 8.0%-9.0 | %          | 9.0      | %          |

 

***Impact of 2003 Medicare Legislation***— On Dec. 8, 2003, President Bush signed intolaw the Medicare Prescription Drug, Improvement and Modernization Act of 2003(the Act). The Act expanded Medicare to include, for the first time, coveragefor prescription drugs. This new coverage is generally effective Jan. 1, 2006.Many of Xcel Energy’s retiree medical programs provide 

 

43

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prescription drug coveragefor retirees over age 65 with coverage at least equivalent to the benefit to beprovided under Medicare. While retirees remain in Xcel Energy’s postretirementhealth care plan without participating in the new Medicare prescription drugcoverage, Medicare will share the cost of Xcel Energy’s plan. This legislationhas therefore reduced Xcel Energy’s share of the obligation for future retireemedical benefits.

 

As of Dec. 31, 2003, XcelEnergy had reduced the postretirement health care benefit obligation by $64.6million due to the expected sharing of the cost of the program by Medicareunder the new legislation.  Also,beginning in 2004, the annual net periodic postretirement benefit cost was reducedby approximately $10 million as a result of the expected sharing of the cost ofthe program by Medicare, with similar savings expected in subsequentyears.  These estimated reductions do notreflect any changes that may result in future levels of participation in theplan or the associated per capita claims cost due to the availability ofprescription drug coverage for Medicare-eligible retirees. Also, in reflectingthis legislation, Medicare cost sharing for a plan has been assumed only ifXcel Energy’s projected contribution to the plan is expected to be at leastequal to the Medicare Part D basic benefit.

 

# **ProjectedBenefit Payments**

# ** **

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

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

 

**9. Detailof Interest and Other Income, Net of Nonoperating Expenses**

 

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

 
| **(Thousands of dollars)**                                                                        | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                                                              |       |     |       |     |       |     |       |
| Interest income                                                                                   |       | $        | 9,194      |     | $          | 3,240    |       | $ | 1,575 |   |
| Other nonoperating income                                                                         |       | 1,322    |       | 1,970    |       | 581      |       |
| Gain on disposal of assets                                                                        |       | 6,583    |       | 1,765    |       | 4,622    |       |
| Interest expense on corporate-owned life insurance and other employee-related  insurance policies |       | (17,075  | )          | (13,995  | )          | (11,301  | )          |
| Other nonoperating expense                                                                        |       | —   |       | —   |       | (118     | )          |
| Total interest and other income, net of nonoperating expenses                                     |       | $        | 24         |     | $          | (7,020   | )          | $ | (4,641 | ) |

 

44

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**10. DerivativeInstruments**

** **

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

 

***Utility CommodityPrice Risk —***PSCo is exposed to commodity price risk in its generation and retaildistribution operations.  Commodity pricerisk is managed by entering into both long- and short-term physical purchaseand sales contracts for electric power, natural gas, coal and fuel oil.  Commodity risk also is managed through theuse of financial derivative instruments. PSCo utilizes these derivative instruments to reduce the volatility inthe cost of commodities acquired on behalf of its retail customers even thoughregulatory jurisdiction may provide for a dollar-for-dollar recovery of actualcosts.  In these instances, the use ofderivative instruments is done consistently with the local jurisdictional costrecovery mechanism.  PSCo’s riskmanagement policy allows it to manage market price risk within eachrate-regulated operation to the extent such exposure exists.

 

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

 

***Interest Rate Risk —***PSCo is subject to the risk of fluctuatinginterest rates in the normal course of business.  PSCo’s risk management policy allows interestrate risk to be managed through the use of fixed rate debt, floating rate debtand interest rate derivatives such as swaps, caps, collars and put or calloptions.

 

# **Typesof and Accounting for Derivative Instruments**

# ** **

PSCo uses a number of different derivative instruments in connectionwith its utility commodity price, interest rate, short-term wholesale andcommodity trading activities, including forward contracts, futures, swaps andoptions.  All derivative instruments notdesignated or those not qualifying for the normal purchases and normal salesexception, as defined by SFAS No. 133, as amended, are recorded at fair value.The classification of the fair value for these derivative instruments isdependent on the designation of a qualifying hedging relationship.  The fair value of derivative instruments notdesignated in a qualifying hedging relationship is reflected in currentearnings.  This includes certaininstruments used to mitigate market risk for PSCo and all instruments relatedto the commodity trading operations.  Thedesignation of a cash flow hedge permits the classification of fair value to berecorded within Other Comprehensive Income, to the extent effective.  The designation of a fair value hedge permitsa derivative instrument’s gains or losses to offset the related results of thehedged item in the Consolidated Statements of Income, to the extent effective.

 

SFAS No. 133, as amended, requires that the hedging relationship behighly effective and that a company formally designate a hedging relationshipto apply hedge accounting.  PSCo formallydocuments hedging relationships, including, among other things, theidentification of the hedging instrument and the hedged transaction, as well asthe risk management objectives and strategies for undertaking the hedgedtransaction.  PSCo also formallyassesses, both at inception and on a regular basis, if required, whether thederivative instruments being used are highly effective in offsetting changes ineither the fair value or cash flows of the hedged items.

 

Hedge effectiveness is recorded based on the nature of the item beinghedged.  Hedging transactions for thesales of electric energy are recorded as a component of revenue, hedgingtransactions for fuel used in energy generation are recorded as a component offuel costs, hedging transactions for natural gas purchased for resale arerecorded as a component of natural gas costs and hedging transactions forinterest rate swaps and lock agreements are recorded as a component of interestexpense.  PSCo is allowed to recover inelectric or natural gas rates the costs of certain financial instrumentsacquired to reduce commodity cost volatility.

 

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

 

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# **CashFlow Hedges**

# ** **

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

 

***Commodity Cash FlowHedges******—***PSCo enters into derivative instruments tomanage variability of future cash flows from changes in commodity prices.  These derivative instruments are designatedas cash flow hedges for accounting purposes. At Dec. 31, 2004, PSCo had various commodity-related contractsclassified as cash flow hedges extending through 2009.  Amounts deferred from current earnings arerecorded in earnings as the hedged purchase or sales transaction is settled.  This could include the purchase or sale ofenergy and energy-related products, the use of natural gas to generate electricenergy or natural gas purchased for resale.

 

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

 

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

 

***Interest Rate CashFlow Hedges*** — PSCo enters into****interest rate lock agreements, includingtreasury-rate locks and forward starting swaps, that effectively fix the yieldor price on a specified treasury security for a specific period.  These derivative instruments are designatedas cash flow hedges for accounting purposes.

 

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

 

PSCohad no ineffectiveness related to interest rate cash flow hedges during theyears ended Dec. 31, 2004 and 2003, respectively.

 

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

 
| **(Millions of dollars)**                                                           | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|
|                                                                                |       |       |       |
| Accumulated other comprehensive loss related to hedges at Dec. 31,  2001            |       | $          | (4.3       | ) |
| After-tax net unrealized gains related to derivatives accounted for  as hedges      |       | 10.3       |       |
| After-tax net realized gains on derivative transactions reclassified  into earnings |       | (5.0       | )          |
| Accumulated other comprehensive income related hedges at Dec. 31,  2002             |       | $          | 1.0        |   |
|                                                                                |       |       |       |
| After-tax net unrealized gains related to derivative accounted for as  hedges       |       | 18.0       |       |
| After-tax net realized gains on derivative transactions reclassified  into earnings |       | (1.8       | )          |
| Accumulated other comprehensive income related to hedges at Dec. 31,  2003          |       | $          | 17.2       |   |
|                                                                                |       |       |       |
| After-tax net unrealized gains related to derivatives accounted for  as hedges      |       | 8.6        |       |
| After-tax net realized gains on derivative transactions reclassified  into earnings |       | (10.1      | )          |
| Accumulated other comprehensive income related to hedges at Dec. 31,  2004          |       | $          | 15.7       |   |

 

**Fair ValueHedges**

 

The effective portion ofthe change in the fair value of a derivative instrument qualifying as a fairvalue hedge is offset against the change in the fair value of the underlyingasset, liability or firm commitment being hedged.  That is, fair value hedge accounting allowsthe 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 fairvalue is recognized in current earnings.

 

At Dec. 31, 2004, PSCohad no fair value hedges.

 

**NormalPurchases or Normal Sales Contracts**

** **

PSCo enters intocontracts for the purchase and sale of various commodities for use in itsbusiness operations.  SFAS No. 133requires a company to evaluate these contracts to determine whether thecontracts are derivatives.  Certaincontracts that literally meet the 

 

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definition of aderivative may be exempted from SFAS No. 133, as amended, as normal purchasesor normal sales.  Normal purchases andnormal sales are contracts that provide for the purchase or sale of somethingother than a financial instrument or derivative instrument that will bedelivered in quantities expected to be used or sold over a reasonable period inthe normal course of business.  Inaddition, normal purchases and normal sales contracts must have a price basedon an underlying that is clearly and closely related to the asset beingpurchased or sold.  An underlying is aspecified interest rate, security price, commodity price, foreign exchangerate, index of prices or rates, or other variable, including the occurrence ornonoccurrence of a specified event, such as a scheduled payment under acontract.

 

Contracts that meet therequirements of normal are documented and exempted from the accounting andreporting requirements of SFAS No. 133. In June 2003, C20 clarified the terms clearly and closely related tonormal purchases and sales contracts, as included in SFAS No. 133, asamended.  PSCo’s implementation of C20 in2003 had no impact on earnings.  However,certain contracts did require a one-time fair value adjustment as of Oct. 1,2003.  The result of this adjustment wasthe creation of a derivative liability with an offsetting regulatory asset toreflect expected recovery of the amounts from customers.  The derivative liability and relatedregulatory asset will be amortized over the respective lives of thecontracts.  See Note 13 to theConsolidated Financial Statements.

 

PSCo evaluates all of itscontracts when such contracts are entered to determine if they are derivativesand, if so, if they qualify to meet the normal designation requirements underSFAS No. 133.  None of the contractsentered into within the commodity trading operations qualify for a normaldesignation.

 

Normal purchases andnormal sales contracts are accounted for as executory contracts as requiredunder GAAP.

 

Thefair value of qualifying hedges is presented as a component of OtherComprehensive Income in the Consolidated Statements of Stockholder’sEquity.  At Dec. 31, 2004 and 2003, thefair value of these contracts was $(16.4) million and $(10.6) million,respectively.

 

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

 

Fora further discussion of other financial instruments at PSCo, see Note 11 to theConsolidated Financial Statements.

 

**11.Financial Instruments**

 

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

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

** **

The fair value of cashand cash equivalents, notes and accounts receivable and notes and accountspayable are not materially different from their carrying amounts because of theshort-term nature of these instruments or because the stated rates approximatemarket rates.  The fair values of PSCo'slong-term investments are estimated based on quoted market prices for those orsimilar investments.  The fair value ofPSCo's long-term debt is estimated based on the quoted market prices for thesame or similar issues or the current rates for debt of the same remainingmaturities and credit quality.

 

The fair value estimatespresented are based on information available to management as of Dec. 31, 2004and 2003. These fair value estimates have not been comprehensively revalued forpurposes of these Consolidated Financial Statements since that date, andcurrent estimates of fair values may differ significantly.

 

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

 
| **(Millions of dollars)  Nature of Guarantee**                                                          | ** ** | **Guarantor** | ** ** | **Guarantee  Amount** | ** ** | **Current  Exposure** | ** ** | **Term or Expiration Date** | ** ** | **Triggering  Event  Requiring  Performance** | ** ** | **Assets Held as   Collateral** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|---------------|------------|-----------------------|------------|-----------------------|------------|-----------------------------|------------|-----------------------------------------------|------------|---------------------------------|------------|
|                                                                                                    |       |          |       |                  |       |                  |       |                        |       |                                          |       |                            |       |
| Primarily bonds to guarantee restoration of  sites that have been disturbed to access utility equipment |       | PSCo          |       | $                     | 0.5        |                  | $          | 0.0                         |       | 2005                                          |       | (a)                             |       | N/A |   |
|                                                                                                         |            |               |            |                       |            |                       |            |                             |            |                                               |            |                                 |            |  |  |

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(a)          Failure of PSCo to perform under the agreement, which is the subject ofthe relevant bond.  In addition, per theindemnity agreement between PSCo and the various surety companies, the suretycompanies have the discretion to demand collateral be posted.

 

 

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# **Lettersof Credit**

# ** **

PSCo use letters of credit,generally with terms of one year, to provide financial guarantees for certainoperating obligations.  At Dec. 31, 2004,there was $11.3 million of letters of credit outstanding. The contract amountsof these letters of credit approximate their fair value and are subject to feesdetermined in the marketplace.

 

**12.Commitments and Contingent Liabilities**

 

***Tax Matters —***PSCo’s wholly owned subsidiary, PSRInvestments, 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 anddeductions taken on the interest expense on these borrowings. The InternalRevenue Service (IRS) has challenged the deductibility of such interest expensedeductions and has disallowed the deductions taken in tax years 1993 through1999.

 

Afterconsultation with tax counsel, Xcel Energy contends that the IRS determinationis not supported by tax law. Based upon this assessment, management believesthat the tax deduction of interest expense on the COLI policy loans is in fullcompliance with the law. Accordingly, PSRI has not recorded any provision forincome tax or related interest or penalties that may be imposed by the IRS andhas continued to take deductions for interest expense related to policy loanson its income tax returns for subsequent years.

 

In April 2004,Xcel Energy filed a lawsuit in U.S. District Court for the District ofMinnesota against the IRS to establish its entitlement to deduct policy loaninterest for tax years 1993 and 1994.  InDecember 2004, Xcel Energy filed suit in U.S. Tax Court in Washington D.C. fortax years 1995 through 1997.  Xcel Energyexpects to request that the tax court stay its petition pending the decision inthe district court litigation.  Thelitigation could require several years to reach final resolution. Although theultimate resolution of this matter is uncertain, it could have a materialadverse effect on PSCo’s financial position and results of operations. Defenseof Xcel Energy’s position may require significant cash outlays, which may ormay not be recoverable in a court proceeding.

 

Should the IRSultimately prevail on this issue, tax and interest payable through Dec. 31,2004, would reduce earnings by an estimated $311 million.  In 2004, PSCo received formal notificationthat the IRS will seek penalties. If penalties (plus associated interest) arealso included, the total exposure through Dec. 31, 2004, is approximately $368million.  PSCo estimates its annualearnings for 2004 would be reduced by $36 million, after tax, if COLI interestexpense deductions were no longer available.

 

***Accounting forUncertain Tax Positions***– In late July 2004, theFASB discussed potential changes or clarifications in the criteria forrecognition of tax benefits, which may result in raising the threshold forrecognizing tax benefits, which have some degree of uncertainty. The FASB hasnot issued any proposed guidance, but an exposure draft may be released in thefirst quarter of 2005 PSCo is unable to determine the impact or timing of anypotential accounting changes required by the FASB, but such changes could havea material financial impact.

 

***Leases*****— PSColeases a variety of equipment and facilities used in the normal course ofbusiness. Some of these leases qualify as capital leases and are accounted foraccordingly. The capital leases contractually expire in 2025 and 2029. The netbook value of property under capital leases was approximately $48.9 million and$47.7 million at Dec. 31, 2004 and 2003, respectively. Assets acquired undercapital leases are recorded as property at the lower of fair-market value orthe present value of future lease payments and are amortized over their actualcontract term in accordance with practices allowed by regulators. The relatedobligation is classified as long-term debt. Executory costs are excluded fromthe minimum lease payments.

 

The remainder of the leases,primarily real estate leases and leases of coal-hauling railcars, trucks, carsand power-operated equipment are accounted for as operating leases.  Rental expense under operating leaseobligations was approximately $17.6 million, $22.4 million and $22.6 millionfor 2004, 2003 and 2002, respectively.

 

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Expected operating leaseexpenses are:

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

 

Future commitments underPSCo’s two capital leases are:

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

 

***Fuel Contracts*****—PSCo has contracts providing for the purchase and delivery of a significantportion of its current coal and natural gas requirements. These contractsexpire in various years between 2005 and 2025. In addition, PSCo is required topay additional amounts depending on actual quantities shipped under theseagreements. The potential risk of loss for PSCo, in the form of increased costsfrom market price changes in fuel, is mitigated through the cost-of-energyadjustment provision of the ratemaking process, which provides for recovery ofmost fuel costs.

 

The estimated minimumpurchase for PSCo under these contracts as of Dec. 31, 2004, is as follows:

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

 

***Purchased Power Agreements****—*PSCo has entered into agreements withutilities and other energy suppliers for purchased power to meet system loadand energy requirements, replace generation from company-owned units undermaintenance and during outages, and meet operating reserve obligations. PSCohas various pay-for-performance contracts with expiration dates through theyear 2019. In general, these contracts provide for capacity payments, subjectto meeting certain contract obligations and energy payments based on actualpower taken under the contracts. Certain contractual payment obligations areadjusted based on indexes.  However, theeffect of these price adjustments are mitigated through cost-of-energy adjustmentmechanisms.

 

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

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

 

***Plant Removal Costs***- PSCo records aregulatory liability for plant removal costs for generation, transmission anddistribution facilities.  The recordingof the obligation has no income statement impact due to the deferral ofadjustments, through the establishment of a regulatory asset pursuant to SFASNo. 71.  Generally, the accrual of futurenon-legal removal obligations is not required. However, long-standing ratemaking practices approved by applicable stateand federal regulatory commissions have allowed provisions for such costs inhistorical depreciation rates.  Theseremoval costs have accumulated over a number of years based on varying rates asauthorized by the appropriate regulatory entities. Given the long periods overwhich the amounts were accrued and the changing of rates through time, PSCo hasestimated the amount of removal costs accumulated through historic depreciationexpense based on current factors used in the existing depreciation rates.  Removal costs as of Dec. 31, 2004 and 2003are $383 million and $351 million, respectively.

 

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**EnvironmentalContingencies**

 

PSCo is subject toregulations covering air and water quality, the storage of natural gas and thestorage and disposal of hazardous or toxic wastes.  We continuously assess our compliance.Regulations, interpretations and enforcement policies can change, which mayimpact the cost of building and operating our facilities.

 

***Site Remediation****—*PSComust pay all or a portion of the cost to remediate sites where past activitiesof PSCo and some other parties have caused environmental contamination.  At Dec. 31, 2004 there were three categoriesof sites:

 

•                  the site of a former federal uraniumenrichment facility,

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

•                  thirdparty sites, such as landfills, to which we are alleged to be a potentiallyresponsible party (PRP) that sent hazardous materials and wastes.

 

PSCo records a liabilitywhen there is enough information to develop an estimate of the cost ofremediating a site and revise the estimate as information is received.  The estimated remediation cost may varymaterially.

 

To estimate the cost toremediate these sites, PSCo may have to make assumptions where facts are notfully known. For instance, PSCo might make assumptions about the nature andextent of site contamination, the extent of required cleanup efforts, costs ofalternative cleanup methods and pollution control technologies, the period overwhich remediation will be performed and paid for, changes in environmentalremediation and pollution control requirements, the potential effect oftechnological improvements, the number and financial strength of other PRPs andthe identification of new environmental cleanup sites.

 

Estimates are revised asfacts become known, but at Dec. 31, 2004, PSCo estimated its liability for thecost of remediating sites was $9.7 million, of which $8.7 million wasconsidered to be a current liability.

 

Some of the cost ofremediation may be recovered from:

 

•      insurancecoverage;

•      otherparties that have contributed to the contamination; and

•      customers.

 

Neither the totalremediation cost nor the final method of cost allocation among all PRPs of theunremediated sites has been determined. PSCo has recorded estimates of itsfuture costs for these sites.

 

***Federal Uranium Enrichment Facility***

 

Approximately $0.8 millionof the long-term liability for PSCo relates to a DOE assessment fordecommissioning a federal uranium enrichment facility. This environmentalliability does not include accruals recorded and collected from customers inrates for future nuclear fuel disposal.

 

###### ***Manufactured Gas Plant Site***

 

***Fort Collins MGP Site*****—**Priorto 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in FortCollins, Colo., not far from the Cache la Poudre River. In 1926, afteracquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has soldmost of the property.  Recently, an oilysubstance similar to MGP byproducts was discovered in the Cache la PoudreRiver.  In early 2004, PSCo completedimplementation of a work plan to further investigate the sources ofcontamination of the river at a cost of approximately $1.4 million.  The work resulted in removal of contaminatedsediments and delineation of the extent of the contamination.

 

OnNov. 10, 2004, PSCo entered into an agreement with the EPA, the city of FortCollins and Schrader Oil Co., under which PSCo will perform remediation andmonitoring work at an estimated cost of $8.8 million.  Work is currently underway, with completionof construction anticipated in June 2005 followed by ongoing operation andmaintenance.

 

To date, PSCo has spentapproximately $3.4 million on the project, including settlement costsnegotiated with the City of Fort Collins 

 

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in 1998 and costs incurredby the EPA.  The EPA is also expected toseek recovery from PSCo of its ongoing oversight costs.  PSCo has deferred the costs recorded to dateas a regulatory asset and believes that they will be recovered through futurerates. Any costs that are not recoverable from customers will be expensed.

 

***Third Party and Other Environmental Site Remediation***

*** ***

***Asbestos Removal****—*Someof our facilities contain asbestos. Most asbestos will remain undisturbed untilthe facilities that contain it are demolished or renovated. Since we intend tooperate most of these facilities indefinitely, we cannot estimate the amount ortiming of payments for its final removal. It may be necessary to remove someasbestos to perform maintenance or make improvements to other equipment. Thecost of removing asbestos as part of other work is immaterial and is recordedas incurred as operating expenses for maintenance projects, capitalexpenditures for construction projects or removal costs for demolitionprojects.

 

***Federal Clean Water Act***–The federal Clean Water Act addresses the environmental impacts of coolingwater intakes. In July 2004, the EPA published phase II of the rule thatapplies to existing cooling water intakes at steam-electric power plants. Therule will require PSCo to perform additional environmental studies at 3 powerplants in Colorado to determine the impact the facilities may be having onaquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performancestandards established by the phase II rule, physical and/or operational changesmay be required at these plants.  It isnot possible to provide an accurate estimate of the overall cost of thisrulemaking at this time due to the many uncertainties involved. Based on thelimited information available, total capital costs to PSCo are estimated atapproximately $3 million. Actual costs may be significantly higher or lowerdepending on issues such as the resolution of outstanding third-party legalchallenges to the rule.

 

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

 

***Leyden Gas Storage Facility*****—**In February 2001, the CPUC approved PSCo’splan to abandon the Leyden natural gas storage facility (Leyden) after 40 yearsof operation.  In July 2001, the CPUCdecided that the recovery of all Leyden costs would be addressed in a futurerate proceeding when all costs were known. In 2003, PSCo began flooding the facility with water, as part of anoverall plan to convert Leyden into a municipal water storage facility ownedand 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 beforeconversion.  Leyden is expected to closeby Dec. 31, 2005, and the city of Arvada will take over the site. PSCo isobligated to monitor the site for two years after closure. As of Dec. 31, 2004,PSCo has incurred approximately $4.8 million of costs associated withengineering buffer studies, damage claims paid to landowners and other initialclosure costs.  PSCo has accrued anadditional $1.3 million of costs expected to be incurred through 2006 tocomplete the decommissioning and closure of the facility.  PSCo has deferred these costs as a regulatoryasset and believes that these costs will be recovered through future rates. Anycosts that are not recoverable from customers will be expensed.

 

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

 

***PSCo Notice of Violation*****— On Nov. 3, 1999, the U.S. Department ofJustice filed suit against a number of electric utilities for allegedviolations of the federal Clean Air Act’s New Source Review (NSR)requirements.  The suit is related toalleged modifications of electric generating plants located in the South andMidwest. Subsequently, the EPA also issued requests for information pursuant tothe Clean Air Act to numerous other electric utilities, including PSCo, seekingto determine whether these utilities engaged in activities that may have beenin violation of the NSR requirements.  In2001, PSCo responded to the EPA’s initial information requests.

 

On July 1, 2002, PSCoreceived a Notice of Violation (NOV) from the EPA alleging violations of theNSR requirements of the Clean Air Act at the Comanche and Pawnee plants inColorado. The NOV specifically alleges that various maintenance, repair andreplacement projects undertaken at the plants in the mid- to late-1990s shouldhave required a permit under the NSR process. PSCo believes it has acted in full compliance with the Clean Air Act andNSR process. It believes that the projects identified in the NOV fit 

 

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within the routinemaintenance, repair and replacement exemption contained within the NSRregulations or are otherwise not subject to the NSR requirements. PSCo alsobelieves that the projects would be expressly authorized under the EPA’s NSRequipment replacement rulemaking promulgated in October 2003. On Dec. 24, 2003,the U.S. Court of Appeals for the District of Columbia Circuit stayed this rulewhile it considers challenges to it. PSCo disagrees with the assertions containedin the NOV and intends to vigorously defend its position. As required by theClean Air Act, the EPA met with Xcel Energy in September 2002 to discuss theNOV.

 

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

 

**LegalContingencies**

 

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

 

***Carbon Dioxide Emissions Lawsuit***-On July 21, 2004, the attorneys general of eight states and New York City, aswell as several environmental groups, filed lawsuits in U.S. District Court forthe Southern District of New York against five utilities, including XcelEnergy, to force reductions in carbon dioxide (CO2) emissions.  Although PSCo is not named as a party to thislitigation, the requested relief that Xcel Energy cap and reduce its CO2emissions could have a material adverse effect on PSCo.  The other utilities include American ElectricPower Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2is emitted whenever fossil fuel is combusted, such as in automobiles,industrial operations and coal- or gas-fired power plants. The lawsuits allegethat CO2 emitted by each company is a public nuisance as definedunder state and federal common law because it has contributed to globalwarming. The lawsuits do not demand monetary damages. Instead, the lawsuits askthe court to order each utility to cap and reduce its CO2emissions.   In October 2004, Xcel Energyand four other utility companies filed a motion to dismiss the lawsuitcontending that the lawsuit is an attempt to usurp the policy-setting role inthe U.S. Congress and the president.  Theultimate financial impact of these lawsuits, if any, is not determinable atthis time.

 

The issue of globalclimate change is receiving increased attention.  Debate continues in the scientific communityconcerning the extent to which the earth’s climate is warming, the causes ofclimate variations that have been observed, and the ultimate impacts that mightresult from a changing climate.  There isalso considerable debate regarding public policy for the approach that the U.S.should follow to address the issue.  TheUnited Nations-sponsored Kyoto Protocol, which establishes greenhouse gasreduction targets for developed nations, entered into force on Feb. 16,2005.  President Bush has declared thatthe U.S. will not ratify the protocol and is opposed to legislative mandates,preferring a program based on voluntary efforts and research on newtechnologies.  PSCo is closely monitoringthe issue from both scientific and policy perspectives.  While it is not possible to know the eventualoutcome, PSCo believes the issue merits close attention and is taking actionsit believes are prudent to be best positioned for a variety of possible futureoutcomes.  Xcel Energy, including PSCo,is participating in a voluntary carbon management program and has establishedgoals to reduce its volume of carbon dioxide emissions by 12 million tons by2009 and to reduce carbon intensity by 7 percent by 2012.  PSCo’s evaluation process for futuregenerating resources incorporates the risk of future carbon limits through theuse of a carbon cost adder.  PSCo is alsoinvolved in other projects to improve available methods for managing carbon.

 

***Hill, et al., vs. PSCo, et al.***- In late October2003, there were two wildfires in Colorado, one in Boulder County and the otherin Douglas County. There was no loss of life, but there was property damageassociated with these fires. Parties have asserted that trees falling into XcelEnergy distribution lines may have caused one or both fires.  On Jan. 14, 2004, an action against PSCorelating to the fire in Boulder County was filed in Boulder County DistrictCourt. There are now 46 plaintiffs, including individuals and insurancecompanies, and three co-defendants, including PSCo.  The plaintiffs assert that they are seekingin excess of $35 million in damages. PSCo believes it has insurance coverage tomitigate the liability in this matter. The ultimate financial impact to PSCo isnot determinable at this time.

 

**13.Regulatory Assets and Liabilities**

 

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

 

52

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| **(Thousands of dollars)**                                 | ** ** | **See  note** | ** ** | **Remaining amortization  period** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------------------------|------------|---------------|------------|------------------------------------|------------|----------|------------|----------|------------|
|                                                       |       |          |       |                               |       |     |       |     |       |
| Regulatory Assets:                                         |       |          |       |                               |       |     |       |     |       |
| Purchase power contract valuation adjustments (c)          |       | 10            |       | Term of related contract           |       | $        | 83,981     |     | $          | 75,815 |   |
| Employees’ postretirement benefits other than pension |       | 8             |       | Three years                        |       | 31,125   |       | 35,015   |       |
| AFDC recorded in plant (a)                                 |       |          |       | Plant lives                        |       | 42,236   |       | 32,916   |       |
| Conservation programs (a)                                  |       |          |       | Five years                         |       | 44,923   |       | 32,843   |       |
| Losses on reacquired debt                                  |       | 1             |       | Term of related debt               |       | 22,495   |       | 24,555   |       |
| Nuclear decommissioning costs (d)                          |       |          |       | One year                           |       | 7,884    |       | 20,904   |       |
| Plant asset recovery (Pawnee II and Metro Ash)             |       |          |       | 2.5 years                          |       | 12,258   |       | 17,162   |       |
| Deferred income tax adjustments                            |       | 1             |       | Typically plant lives              |       | —   |       | 14,205   |       |
| Unrecovered electric production costs (b)                  |       |          |       | 3 months                           |       | —   |       | 13,779   |       |
| Other                                                      |       |          |       | Various                            |       | 1,662    |       | 2,146    |       |
| Total regulatory assets                                    |       |          |       |                               |       | $        | 246,564    |     | $          | 269,340 |   |
| Regulatory Liabilities:                                    |       |          |       |                               |       |     |       |     |       |
| Plant removals costs                                       |       | 12            |       |                               |       | $        | 383,035    |     | $          | 350,682 |   |
| Investment tax credit deferrals                            |       |          |       |                               |       | 40,663   |       | 43,266   |       |
| Purchase power contract valuation adjustments (c)          |       | 10            |       |                               |       | 26,670   |       | 117,152  |       |
| Deferred income tax adjustments                            |       |          |       |                               |       | 24,768   |       | —   |       |
| Total regulatory liabilities                               |       |          |       |                               |       | $        | 475,136    |     | $          | 511,100 |   |

 

----

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

(b)         Excludes current portion expected to be recovered within the next 12months of $16.1 million and $55.8 million for 2004 and 2003, respectively

(c)          Regulatory assets and liabilities created by the implementation of C20.See Note 10.

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

 

**14. Segmentand Related Information**

 

PSCo has two reportablesegments, Regulated Electric Utility and Regulated Natural Gas Utility.

 

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

 

•                  PSCo’s Regulated Natural Gas Utilitytransports, stores and distributes natural gas in portions of Colorado.

 

Revenues from operatingsegments not included above are below the necessary quantitative thresholds andare therefore included in the All Other category. Those primarily include steamrevenue, appliance repair services and nonutility real estate activities.

 

To report net income forRegulated Electric and Regulated Natural Gas Utility segments, PSCo must assignor allocate all costs and certain other income. In general, costs are:

 

•                  directly assigned wherever applicable;

•                  allocated based on cost causation allocatorswherever applicable; or

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

 

The accounting policies ofthe segments are the same as those described in Note 1 to the ConsolidatedFinancial Statements.

 

In 2003, the process toallocate common costs of the Regulated Electric and Regulated Natural GasUtility segments was revised. Segment results for 2002 have been restated toreflect the revised cost allocation process.

 

53

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| ** **                                 | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|--------------------------------------------|------------|---------------------------------|------------|-------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| ** **                                 | ** ** | **(Thousands of dollars)**      | ** ** |
| **2004**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 2,194,628  |                                | $          | 1,073,989      |       | $                             | 27,825     |                    | $          | — |   | $ | 3,296,442 |   |
| Intersegment revenues                      |       | 180                             |       | 69                                  |       | —         |       | (249                          | )          | —                  |       |
| Total revenues                             |       | 2,194,808                       |       | 1,074,058                           |       | 27,825         |       | (249                          | )          | 3,296,442               |       |
| Depreciation and amortization              |       | 170,337                         |       | 47,167                              |       | 5,938          |       | —                        |       | 223,442                 |       |
| Financing costs, mainly interest expense   |       | 116,686                         |       | 32,033                              |       | 2,409          |       | (1,106                        | )          | 150,022                 |       |
| Income tax expense (benefit)               |       | 80,578                          |       | 19,437                              |       | (27,159        | )          | —                        |       | 72,856                  |       |
| Segment net income                         |       | $                               | 152,870    |                                | $          | 58,513         |       | $                             | 6,622      |                    | $          | — |   | $ | 218,005 |   |
|                                       |       | ** **                      | ** ** | ** **                          | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| **2003**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 2,117,790  |                                | $          | 883,052        |       | $                             | 23,271     |                    | $          | — |   | $ | 3,024,113 |   |
| Intersegment revenues                      |       | 251                             |       | 51                                  |       | —         |       | (302                          | )          | —                  |       |
| Total revenues                             |       | 2,118,041                       |       | 883,103                             |       | 23,271         |       | (302                          | )          | 3,024,113               |       |
| Depreciation and amortization              |       | 178,243                         |       | 43,048                              |       | 5,494          |       | —                        |       | 226,785                 |       |
| Financing costs, mainly interest expense   |       | 123,246                         |       | 35,827                              |       | 8,769          |       | (8,546                        | )          | 159,296                 |       |
| Income tax expense (benefit)               |       | 95,384                          |       | 20,500                              |       | (27,673        | )          | —                        |       | 88,211                  |       |
| Segment net income                         |       | $                               | 148,001    |                                | $          | 70,497         |       | $                             | 9,435      |                    | $          | — |   | $ | 227,933 |   |
|                                       |       |                            |       |                                |       |           |       |                          |       |                    |       |
| **2002**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 1,878,193  |                                | $          | 749,355        |       | $                             | 24,365     |                    | $          | — |   | $ | 2,651,913 |   |
| Intersegment revenues                      |       | 219                             |       | 41                                  |       | —         |       | (260                          | )          | —                  |       |
| Total revenues                             |       | 1,878,412                       |       | 749,396                             |       | 24,365         |       | (260                          | )          | 2,651,913               |       |
| Depreciation and amortization              |       | 192,202                         |       | 53,044                              |       | 2,352          |       | —                        |       | 247,598                 |       |
| Financing costs, mainly interest expense   |       | 109,658                         |       | 32,800                              |       | 15,822         |       | (16,049                       | )          | 142,231                 |       |
| Income tax expense (benefit)               |       | 119,520                         |       | 36,189                              |       | (27,023        | )          | —                        |       | 128,686                 |       |
| Segment net income                         |       | $                               | 184,013    |                                | $          | 66,874         |       | $                             | 13,793     |                    | $          | — |   | $ | 264,680 |   |

 

**15. RelatedParty Transactions**

 

In 2003, Xcel Energyestablished a money pool arrangement with the utility subsidiaries, subject toreceipt of required state regulatory approvals. PSCo received approval to participate in the money pool arrangement in2004.  The money pool allows forshort-term loans between the utility subsidiaries and from the holding companyto the utility subsidiaries at market-based interest rates. The money poolarrangement does not allow loans from the utility subsidiaries to the holdingcompany.  PSCo has approval to borrow upto $250 million under the arrangement. PSCo had no borrowings or loans outstanding under the arrangement atDec. 31, 2004.

 

Xcel Energy Services Inc.provides management, administrative and other services for the subsidiaries ofXcel Energy, including PSCo. The services are provided and billed to eachsubsidiary in accordance with Service Agreements approved by the SEC andexecuted by each subsidiary. Costs are charged directly to the subsidiary whichuses the service whenever possible, and are allocated using an SEC approvedmethod if they cannot be directly assigned.

 

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

 

CheyenneLight, Fuel and Power (Cheyenne), an Xcel Energy subsidiary, purchased all ofits electricity requirements from PSCo. During 2004, Xcel Energy reached anagreement to sell Cheyenne.  The sale wascompleted in January 2005.

 

The table below containssignificant affiliate transactions among the companies and related parties forthe years ended Dec. 31:

 

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

 

Accounts receivable andpayable with affiliates at Dec. 31, was:

 

| ** **                             | ** ** | **2004**                  | ** ** | **2003**               | ** ** |
|----------------------------------------|------------|---------------------------|------------|------------------------|------------|
| **(Thousands of dollars)**             | ** ** | **Accounts   Receivable** | ** ** | **Accounts   Payable** | ** ** | **Accounts   Receivable** | ** ** | **Accounts   Payable** | ** ** |
|                                   |       |                      |       |                   |       |   |   |   |   |
| NSP—Minnesota                     |       | $                         | 12,197     |                   | $          | 72 |   | $ | 714 |   | $ | 20 |   |
| NSP—Wisconsin                     |       | 54                        |       | —                 |       | — |   | 883 |   |
| SPS                                    |       | 334                       |       | 1                      |       | — |   | 10,948 |   |
| Other subsidiaries of Xcel Energy Inc. |       | 7,376                     |       | 35,792                 |       | 5,695 |   | 47,281 |   |
|                                   |       | $                         | 19,961     |                   | $          | 35,865 |   | $ | 6,409 |   | $ | 59,132 |   |

 

54

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

 

**16.Summarized Quarterly Financial Data (Unaudited)**

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

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

 

----

(a)     Fourth quarter 2004 resultswere increased by $13.6 million of income tax benefits related to thesuccessful resolution of various IRS audit issues and other adjustments tocurrent and deferred taxes related to prior years.

** **

**Item 9**—**Changes in and Disagreements With Accountantson Accounting and****FinancialDisclosure**

 

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

 

**Item 9A**— **Controls and Procedures**

 

**Disclosure Controls and Procedures**

** **

PSCo maintains a set ofdisclosure controls and procedures designed to ensure that information requiredto be disclosed in reports that it files or submits under the SecuritiesExchange Act of 1934 is recorded, processed, summarized and reported within thetime periods specified in Securities and Exchange Commission rules and forms.As of the end of the period covered by this report, based on an evaluationcarried out under the supervision and with the participation of the PSCo’smanagement, including the Chief Executive Officer (CEO) and Chief FinancialOfficer (CFO), of the effectiveness of its disclosure controls and procedures,the CEO and CFO have concluded that the Company’s disclosure controls andprocedures are effective.

 

**InternalControl Over Financial Reporting**

** **

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

 

**Item 9B**— **Other Information**

** **

None

 

**PART III**

 

Items 10, 11, 12 and 13 ofPart III of Form 10-K have been omitted from this report for PSCo in accordancewith conditions set forth in general instructions I (1) (a) and (b) of Form10-K for wholly-owned subsidiaries.

 

**Item10 — Directors and Executive Officers of the Registrant**

** **

**Item 11**— **Executive Compensation**

 

55

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**Item 12**—**Security Ownership of Certain BeneficialOwners and Management**

 

**Item 13**—**Certain Relationships and RelatedTransactions**

** **

**Item 14**—**Principal Accounting Fees and Services**

 

Information concerning feespaid to the principal accountant for each of the last two years is contained inthe Xcel Energy Proxy Statement for its 2005 Annual Meeting of Shareholders,which is incorporated by reference.

 

**PART IV**

 

**Item 15**—**Exhibits, Financial Statement Schedules**

** **

1.               Consolidated Financial Statements:

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

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

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31, 2004, 2003 and2002.

Consolidated Balance Sheets **—**Asof Dec. 31, 2004 and 2003.

 

2.         ScheduleII **—**Valuation and Qualifying Accounts andReserves for the years ended Dec. 31, 2004, 2003 and 2002.

 

3.         Exhibits

                  *Indicatesincorporation by reference

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

 

| **Dated as of** | ** ** | **Previous  Filing: Form;  Date or File No.** | ** ** | **Exhibit  No.** | ** ** | **Dated  as of** | ** ** | **Previous  Filing: Form;  Date or File No.** | ** ** | **Exhibit  No.** | ** ** |
|-----------------|------------|-----------------------------------------------|------------|------------------|------------|------------------|------------|-----------------------------------------------|------------|------------------|------------|
| ** **      | ** ** | ** **                                    | ** ** | ** **       | ** ** | ** **       | ** ** | ** **                                    | ** ** | ** **       | ** ** |
| March 14, 1941  |       | 10, 1946                                      |       | B-2              |       | March 1, 1974    |       | 8-K, April 1974                               |       | 2                |       |
| May 14, 1941    |       | 10, 1946                                      |       | B-3              |       | Dec. 1, 1974     |       | 8-K, December 1974                            |       | 1                |       |
| April 28, 1942  |       | 10, 1946                                      |       | B-4              |       | Oct. 1, 1975     |       | S-7, (2-60082)                                |       | 2                | (b)(3)     |
| April 14, 1943  |       | 10, 1946                                      |       | B-5              |       | April 28, 1976   |       | S-7, (2-60082)                                |       | 2                | (b)(4)     |
| April 27, 1944  |       | 10, 1946                                      |       | B-6              |       | April 28, 1977   |       | S-7, (2-60082)                                |       | 2                | (b)(5)     |
| April 18, 1945  |       | 10, 1946                                      |       | B-7              |       | Nov. 1, 1977     |       | S-7, (2-62415)                                |       | 2                | (b)(3)     |
| April 23, 1946  |       | 10-K, 1946                                    |       | B-8              |       | April 28, 1978   |       | S-7, (2-62415)                                |       | 2                | (b)(4)     |
| April 9, 1947   |       | 10-K, 1946                                    |       | B-9              |       | Oct. 1, 1978     |       | 10-K, 1978                                    |       | D                | (1)        |
| June 1, 1947    |       | S-1, (2-7075)                                 |       | 7                | (b)        | Oct. 1, 1979     |       | S-7, (2-66484)                                |       | 2                | (b)(3)     |
| April 1, 1948   |       | S-1, (2-7671)                                 |       | 7                | (b)(1)     | March 1, 1980    |       | 10-K, 1980                                    |       | 4                | (c)        |
| May 20, 1948    |       | S-1, (2-7671)                                 |       | 7                | (b)(2)     | April 28, 1981   |       | S-16, (2-74923)                               |       | 4                | (c)        |
| Oct. 1, 1948    |       | 10-K, 1948                                    |       | 4                |       | Nov. 1, 1981     |       | S-16, (2-74923)                               |       | 4                | (c)        |
| April 20, 1949  |       | 10-K, 1949                                    |       | 1                |       | Dec. 1, 1981     |       | 10-K, 1981                                    |       | 4                | (c)        |
| April 24, 1950  |       | 8-K, April 1950                               |       | 1                |       | April 29, 1982   |       | 10-K, 1982                                    |       | 4                | (c)        |
| April 18, 1951  |       | 8-K, April 1951                               |       | 1                |       | May 1, 1983      |       | 10-K, 1983                                    |       | 4                | (c)        |
| Oct. 1, 1951    |       | 8-K, November 1951                            |       | 1                |       | April 30, 1984   |       | S-3, (2-95814)                                |       | 4                | (c)        |
| April 21, 1952  |       | 8-K, April 1952                               |       | 1                |       | March 1, 1985    |       | 10-K, 1985                                    |       | 4                | (c)        |
| Dec. 1, 1952    |       | S-9, (2-11120)                                |       | 2                | (b)(9)     | Nov. 1, 1986     |       | 10-K, 1986                                    |       | 4                | (c)        |
| April 15, 1953  |       | 8-K, April 1953                               |       | 2                |       | May 1, 1987      |       | 10-K, 1987                                    |       | 4                | (c)        |
| April 19, 1954  |       | 8-K, April 1954                               |       | 1                |       | July 1, 1990     |       | S-3, (33-37431)                               |       | 4                | (c)        |
| Oct. 1, 1954    |       | 8-K, October 1954                             |       | 1                |       | Dec. 1, 1990     |       | 10-K, 1990                                    |       | 4                | (c)        |
| April 18, 1955  |       | 8-K, April 1955                               |       | 1                |       | March 1, 1992    |       | 10-K, 1992                                    |       | 4                | (d)        |
| April 24, 1956  |       | 10-K, 1956                                    |       | 1                |       | April 1, 1993    |       | 10-Q, June 30, 1993                           |       | 4                | (a)        |
| May 1, 1957     |       | S-9, (2-13260)                                |       | 2                | (b)(15)    | June 1, 1993     |       | 10-Q, June 30, 1993                           |       | 4                | (b)        |
| April 10, 1958  |       | 8-K, April 1958                               |       | 1                |       | Nov. 1, 1993     |       | S-3, (33-51167)                               |       | 4                | (a)(3)     |

 

56

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

 
| 4.03* |   | Indenture,  dated as of Oct. 1, 1993, providing for the issuance of First Collateral  Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)). |
|-------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.04* |   | Indentures supplemental to  Indenture dated as of Oct. 1, 1993:                                                                                    |

 

| **Dated  as of** | ** ** | **Previous  Filing:  Form; Date or   File No.** | ** ** | **Exhibit  No.** | ** ** | **Dated  as of** | ** ** | **Previous Filing:   Form; Date or****File No.** | ** ** | **Exhibit  No.** | ** ** |
|------------------|------------|-------------------------------------------------|------------|------------------|------------|------------------|------------|--------------------------------------------------|------------|------------------|------------|
| ** **       | ** ** | ** **                                      | ** ** | ** **       | ** ** | ** **       | ** ** | ** **                                       | ** ** | ** **       |       |
| Nov. 1, 1993     |       | S-3, (33-51167)                                 |       | 4                | (b)(2)     | Aug. 15, 2002    |       | 10-Q, Sept. 30, 2002                             |       | 4.03             |       |
| Jan. 1, 1994     |       | 10-K, 1993                                      |       | 4                | (b)(3)     | Sept. 1, 2002    |       | 8-K, Sept. 18, 20024.01                          |       | 4.01             |       |
| Sept. 2, 1994    |       | 8-K, September 1994                             |       | 4                | (b)        | Sept. 15, 2002   |       | 10-Q, Sept. 30, 2002                             |       | 4.04             |       |
| May 1, 1996      |       | 10-Q, June 30, 1996                             |       | 4                | (b)        | March 1, 2003    |       | S-3 April 14, 2003 (333-104504)                  |       | 4                | (b)(3)     |
| Nov. 1, 1996     |       | 10-K, 1996                                      |       | 4                | (b)(3)     | April 1, 2003    |       | 10-Q May 15, 2003 (001-03034)                    |       | 4.02             |       |
| Feb. 1, 1997     |       | 10-Q, March 31, 1997                            |       | 4                | (b)        | May 1, 2003      |       | S-4, June 11, 2003 (333-106011)                  |       | 4.9              |       |
| April 1, 1998    |       | 10-Q, March 31, 1998                            |       | 4                | (b)        | Sept 1, 2003     |       | 8-K, Sept. 2, 2003 (001-03280)                   |       | 4.02             |       |
|             |       |                                            |       |             |       | Sept. 15, 2003   |       | Xcel Energy 10-K, Mar. 15,  2004 (001-03034)     |       | 4.100            |       |

 
| 4.05*   |   | Indenture dated July 1,  1999, between Public Service Co. of Colorado and The Bank of New York,  providing for the issuance of Senior Debt Securities and Supplemental  Indenture dated July 15, 1999, between PSCo and The Bank of New York  (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999). |
|---------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.06*   |   | Registration Rights  Agreement dated March 14, 2003 among Public Service Co. of Colorado, Bank One  Capital Markets, Inc. and UBS Warburg LLC (Exhibit 4.1 to Form S-4 (file no.  333-106011) dated June 11, 2003).                                                                                                        |
| 4.07*   |   | Credit Agreement between  Public Service Co. of Colorado, Bank One NA, Wells Fargo Bank Minnesota NA  and other financial institutions dated May 14, 2004 (Exhibit 4.01 to Xcel  Energy Form 10-Q (file no. 001-03034) dated June 30, 2004).                                                                               |
| 10.01*+ |   | Xcel Energy Omnibus  Incentive Plan (Exhibit A to Xcel Energy Form DEF-14A (file no. 001-03034)  filed Aug. 29, 2000).                                                                                                                                                                                                     |
| 10.02*+ |   | Xcel Energy Executive  Annual Incentive Award Plan (Exhibit B to Xcel Energy Form DEF-14A (file no.  001-03034) filed Aug. 29, 2000).                                                                                                                                                                                      |
| 10.03*+ |   | Employment Agreement dated  March 24, 1999, among Northern States Power Co. (a Minnesota corporation),  New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New  Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).                                                              |
| 10.04*+ |   | Amended and Restated  Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota  Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).                                                                                                                                               |
| 10.05*+ |   | Stock Equivalent Plan for  Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct.  1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for  the year 1997).                                                                                                                      |
| 10.06*+ |   | Senior Executive Severance  Policy, effective March 24, 1999, between New Century Energies, Inc. and  Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (File  no. 001-12927) dated March 31, 1999).                                                                                            |
| 10.07*+ |   | New Century Energies  Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A  (file no. 001-12927) filed March 26, 1998).                                                                                                                                                                            |

 

57

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| 10.08*+ |   | Directors’ Voluntary  Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                  |
|---------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.09*+ |   | Supplemental Executive  Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                   |
| 10.10*+ |   | Salary Deferral and  Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New  Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                     |
| 10.11*+ |   | Salary Deferral and  Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century  Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                           |
| 10.12*+ |   | Supplemental Executive  Retirement Plan for Key Management Employees, as amended and restated March  26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (File no. 001-3280) dated Dec.  31, 1991).                                                                                                     |
| 10.13*+ |   | Form of Key Executive  Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4)  to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1995).                                                                                                                             |
| 10.14*+ |   | Supplemental Retirement  Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (File  no. 001-03789) dated Aug. 31, 1996).                                                                                                                                                       |
| 10.15*+ |   | Xcel Energy Senior  Executive Severance and Change-in Control Policy dated Oct. 22, 2003 (Exhibit  10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                            |
| 10.16*+ |   | Stock Equivalent Plan for  Non-employee Directors of Xcel Energy as amended and restated Jan. 1, 2004  (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) dated Apr. 9,  2004).                                                                                                         |
| 10.17*+ |   | Xcel Energy Nonqualified  Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy  Form 10-K (file no. 001-03034) dated March 15, 2004).                                                                                                                                     |
| 10.18*+ |   | Xcel Energy Inc. Non-employee  Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K  (file no. 001-03034) dated March 15, 2004).                                                                                                                                   |
| 10.19*+ |   | Xcel Energy 401(k) Savings  Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4  (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                                            |
| 10.20*+ |   | New Century Energies, Inc.  Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining  Unit Employees, as amended and restated effective Jan. 1, 2002 but with  certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no 333-112032)  dated Jan. 21, 2004). |
| 10.21*  |   | Form of Services Agreement  between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Xcel  Energy Form U5B (file no. 001-03034) dated Nov. 16, 2000).                                                                                                                             |
| 10.22*  |   | Securities Litigation  Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit  10.01 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).                                                                                                                    |
| 10.23*  |   | ERISA Actions Settlement  Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to  Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).                                                                                                                            |
| 10.24*  |   | Shareholder Derivative  Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005  (Exhibit 10.03 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14,  2005).                                                                                                           |
| 10.25*+ |   | Employment Agreement,  effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended  (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3,  2005).                                                                                                         |
| 10.26*+ |   | Compensation  and reimbursement practices for Xcel Energy non-employee directors (Exhibit  10.26 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                             |
| 10.27*+ |   | Xcel  Energy executive officer salaries, annual bonus targets and long-term  compensation awards for 2005 (Exhibit 10.27 to Xcel Energy Form 10-K (file  no. 001-03034) dated March 3, 2005).                                                                                                    |
| 10.28*+ |   | Amended  Schedule of Participants for Xcel Energy Senior Executive Severance and  Change-in-Control Policy (Exhibit 10.28 to Xcel Energy Form 10-K (file no.  001-03034) dated March 3, 2005).                                                                                                   |
| 10.29*+ |   | Xcel  Energy Executive Annual Incentive Award Plan Form of Restricted Stock  Agreement (Exhibit 10.29 to Xcel Energy Form 10-K (file no. 001-03034) dated  March 3, 2005).                                                                                                                       |
| 10.30*+ |   | Xcel  Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement  (Exhibit 10.30 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3,  2005).                                                                                                                                 |
| 10.31*+ |   | Xcel  Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit  10.31 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).                                                                                                                                      |
| 10.32*+ |   | Xcel  Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement  (Exhibit 10.32 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3,  2005).                                                                                                                                 |
| 10.33*  |   | Amended and Restated Coal  Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1,  1976 between Public Service Co. of Colorado and Amax Inc. on behalf of its  division, Amax Coal Co. (Form 10-K, Dec. 31, 1984 — Exhibit 10(c)(1)).                                  |
| 10.34*  |   | First Amendment to Amended  and Restated Coal Supply Agreement entered into May 27, 1988 but made  effective Jan. 1, 1988 between Public Service Co. of Colorado and Amax Coal  Co. (Form 10-K, Dec. 31, 1988 — Exhibit 10(c)(2)).                                                          |
| 12.01   |   | Statement of Computation  of Ratio of Earnings to Fixed Charges.                                                                                                                                                                                                                                 |
| 23.01   |   | Consent of Independent Registered  Public Accounting Firm.                                                                                                                                                                                                                                       |
| 31.01   |   | Principal Executive Officer’s  certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                     |
| 31.02   |   | Principal Financial  Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted  pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                     |
| 32.01   |   | Certification pursuant to  18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                        |
| 99.01   |   | Statement pursuant to  Private Securities Litigation Reform Act of 1995.                                                                                                                                                                                                                         |

 

58

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# **SCHEDULEII**

 

**PUBLIC SERVICE COMPANY OF COLORADO**

**VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**

**Years Ended Dec. 31, 2004, 2003 and 2002**

 

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

 

----

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

 

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

 

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

 

59

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## **SIGNATURES**

## ** **

Pursuant to the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, the registranthas 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)              |

 

**March 3,2005**

 

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

 
| /s/ WAYNE H. BRUNETTI                           |   |                                             | /s/ GARY R. JOHNSON  |   |
|-------------------------------------------------|--------|--------------------------------------------------|----------------------|--------|
| Wayne H. Brunetti                               |   | Gary R. Johnson                                  |
| Chief Executive Officer,  Chairman and Director |   | Vice President, General  Counsel and Director    |
| (Principal Executive  Officer)                  |   |                                             |
|                                            |   |                                             |
| /s/ TERESA S. MADDEN                            |   |                                             | /s/ RICHARD C. KELLY |   |
| Teresa S. Madden                                |   | Richard C. Kelly                                 |
| Vice President and  Controller                  |   | President, Chief Operating  Officer and Director |
| (Principal Accounting  Officer)                 |   | (Principal Operating  Officer)                   |
|                                            |   |                                             |
| /s/ BENJAMIN G.S. FOWKE  III                    |   |                                             |                 |
| Benjamin G.S. Fowke III                         |   |                                             |
| Vice President and Chief  Financial Officer     |   |                                             |
| (Principal Financial  Officer)                  |   |                                             |

 

60

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