** **

**UNITED STATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

**(MarkOne)**

| **ý** | **ANNUAL REPORT PURSUANT TO  SECTION 13 OR 15(d) OF**                                                                                                                                                                                                                                        |
|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|       | **THE SECURITIES EXCHANGE ACT OF  1934**                                                                                                                                                                                                                                                     |
|       |                                                                                                                                                                                                                                                                                         |
|       | **For the fiscal year ended December 31, 2005**                                                                                                                                                                                                                                              |
|       |                                                                                                                                                                                                                                                                                         |
|       | **OR**                                                                                                                                                                                                                                                                                       |
|       |                                                                                                                                                                                                                                                                                         |
| **o**      | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d) OF**                                                                                                                                                                                                                                    |
|       | **THE SECURITIES EXCHANGE ACT OF  1934**                                                                                                                                                                                                                                                     |
|       |                                                                                                                                                                                                                                                                                         |
|       | **For the transition period from                    to                    **

  |

**COMMISSION FILE NUMBER 001-03280**

 

**PUBLICSERVICE COMPANY OF COLORADO**

(Exact name of registrant as specified in its charter)

 

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

 

**1225 17th Street**

**Denver, Colorado 80202**

(Address of principal executive offices)

(Zip Code)

 

**(303) 571-7511**

(Registrant’s telephone number, including area code)

 

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

 

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

 

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined by Rule 405 of theSecurities Act. o Yes or No ý

 

Indicate by check mark if the registrant isnot required to file reports pursuant to Section 13 or Section 15(d) of theExchange Act. o Yes or No ý

 

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

 

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

 

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer (asdefined in Rule 12b-2 of the Exchange Act). o Largeaccelerated filer o Acceleratedfiler ý Non-accelerated filer

 

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

 

As of Feb. 20, 2006, 100 shares of commonstock, par value $0.01 per share, were outstanding, all of which were held byXcel Energy Inc., a Minnesota corporation.

 

**DOCUMENTS INCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2006 ProxyStatement**

 

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

 

 

 

**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 1A — Risk  Factors                                                                               |
| 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 OF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel Energy Subsidiaries and Affiliates***              |   |                                                                                                                                                                                                                                                                                                                                      |
|------------------------------------------------------------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NSP-Minnesota                                              |   | Northern States Power Co.,  a Minnesota corporation                                                                                                                                                                                                                                                                                       |
| NSP-Wisconsin                                              |   | Northern States Power Co.,  a Wisconsin corporation                                                                                                                                                                                                                                                                                       |
| PSCo                                                       |   | Public Service Company of  Colorado, a Colorado corporation                                                                                                                                                                                                                                                                               |
| PSRI                                                       |   | PSR Investments, Inc.                                                                                                                                                                                                                                                                                                                     |
| SPS                                                        |   | Southwestern Public  Service Co., a New Mexico corporation                                                                                                                                                                                                                                                                                |
| Utility Subsidiaries                                       |   | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                  |
| Xcel Energy                                                |   | Xcel Energy Inc., a  Minnesota corporation                                                                                                                                                                                                                                                                                                |
|                                                       |   |                                                                                                                                                                                                                                                                                                                                      |
| ***Federal and State Regulatory Agencies***                |   |                                                                                                                                                                                                                                                                                                                                      |
| ATSB                                                       |   | Atomic Safety and  Licensing Board                                                                                                                                                                                                                                                                                                        |
| CPUC                                                       |   | Colorado Public Utilities  Commission. The state agency that regulates the retail rates, services and  other aspects of PSCo’s operations in Colorado. The CPUC also has  jurisdiction over the capital structure and issuance of securities by PSCo.                                                                                |
| DOE                                                        |   | United States Department  of Energy                                                                                                                                                                                                                                                                                                       |
| DOL                                                        |   | United States Department  of Labor                                                                                                                                                                                                                                                                                                        |
| EPA                                                        |   | United States  Environmental Protection Agency                                                                                                                                                                                                                                                                                            |
| FERC                                                       |   | Federal Energy Regulatory  Commission. The U.S. agency that regulates the rates and services for  transportation of electricity and natural gas, and the sale of electricity at  wholesale, in interstate commerce, including the sale of electricity at  market-based rates.                                                             |
| IRS                                                        |   | Internal Revenue Service                                                                                                                                                                                                                                                                                                                  |
| OCC                                                        |   | Colorado Office of  Consumer Counsel                                                                                                                                                                                                                                                                                                      |
| SEC                                                        |   | Securities and Exchange  Commission                                                                                                                                                                                                                                                                                                       |
|                                                       |   |                                                                                                                                                                                                                                                                                                                                      |
| ***Fuel, Purchased  Gas and Resource Adjustment Clauses*** |   |                                                                                                                                                                                                                                                                                                                                      |
| AQIR                                                       |   | Air-quality improvement  rider. Recovers, over a 15-year period, the incremental cost (including fuel  and purchased energy) incurred by PSCo as a result of a voluntary plan to  reduce emissions and improve air quality in the Denver metro area.                                                                                      |
| DSM                                                        |   | Demand-side management. Energy conservation and weatherization program for low-income customers.                                                                                                                                                                                                                                          |
| DSMCA                                                      |   | Demand-side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA. |
| ECA                                                        |   | Electric commodity  adjustment. An incentive adjustment mechanism allowing PSCo to compare actual  fuel and purchased energy expense in a calendar year to a benchmark formula.  The ECA then provides for an $11.25 million cap on any cost sharing over or  under an allowed ECA formula rate.                                          |
| GCA                                                        |   | Gas cost adjustment.  Allows PSCo to recover its actual costs of purchased natural gas and natural  gas transportation. The GCA is revised monthly to coincide with changes in  purchased gas costs.                                                                                                                                      |
| ICA                                                        |   | Incentive cost adjustment.  A retail adjustment clause that allowed PSCo to equally share between  electric customers and shareholders certain fuel and purchased energy costs  and expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA  costs was amortized over the period June 1, 2002 through March 31, 2005.        |

 

3

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

•An underlying  and a notional amount or payment provision or both,•Requires no initial  investment or an initial net investment that is smaller than would be  required for other types of contracts that would be expected to have a  similar response to changes in market factors, and•Terms require or permit a  net settlement, can be readily settled net by means outside the contract or  provides for delivery of an asset that puts the recipient in a position not  substantially different from net settlement |
| Distribution                         |   | The system of lines,  transformers, switches and mains that connect electric and natural gas  transmission systems to customers.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| ERISA                                |   | Employee Retirement Income  Security Act                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| FASB                                 |   | Financial Accounting  Standards Board                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| FTRs                                 |   | Financial Transmission  Rights                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| GAAP                                 |   | Generally accepted  accounting principles                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| Generation                           |   | The process of  transforming other forms of energy, such as nuclear or fossil fuels, into  electricity. Also, the amount of electric energy produced, expressed in  megawatts (capacity) or megawatt hours (energy).                                                                                                                                                                                                                                                                                                                                                                                                                   |
| C20                                  |   | Derivatives Implementation  Group of FASB Implementation Issue No. C20. Clarified the terms clearly and  closely related to normal purchases and sales contracts, as included in SFAS  No. 133, as amended.                                                                                                                                                                                                                                                                                                                                                                                                                            |
| JOA                                  |   | Joint operating agreement  among the Utility Subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| LDC                                  |   | Local distribution  company. A company or division that obtains the major portion of its revenues  from the operations of a retail distribution system for the delivery of  electricity or natural gas for ultimate                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

4

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

 

5

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

## ** **

## ** **

6

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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 gasto retail customers and transports customer-owned natural gas. PSCo servesapproximately 1.3 million electric customers and approximately 1.2 millionnatural gas customers in Colorado. The wholesale customers served by PSCocomprised approximately 23 percent of the total Kwh sales in 2005.

 

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. PSCo Capital Trust I, a former specialpurpose financing trust of PSCo, was dissolved in December 2003.

 

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

 

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

 

Besides repealing PUHCA, the Energy Act is alsoexpected to have substantial long-term effects on energy markets, energyinvestment and regulation of public utilities and holding company systems bythe FERC and DOE. FERC and DOE are in various stages of rulemaking inimplementing the Energy Act. While the precise impact of these rulemakingscannot be determined at this time, PSCo generally views the Energy Act aslegislation that will enhance the utility industry going forward.

 

In 2005, Xcel Energy’scontinuing 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***— PSCo intends to focus ongrowing through investments in electric and natural gas rate base to meetgrowing customer demands and to maintain or increase reliability and quality ofservice to customers and through rate case filings with state and federalregulators to increase rates congruent with increasing costs of operationsassociated with such investments.

 

***Utility Restructuring and Retail Competition***— The structureof the utility industry has been subject to change. Merger and acquisitionactivity in the past had been significant as utilities combined to captureeconomies of scale or establish a strategic niche in preparing for the future. Beginningin the late 1990s, many states began studying or implementing some form ofretail electric utility competition.

 

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

 

 

7

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**Summaryof Recent Federal Regulatory Developments**

 

The FERC has jurisdictionover rates for electric transmission service in interstate commerce andelectric energy sold at wholesale, hydro facility licensing, accountingpractices and certain other activities of PSCo. State and local agencies havejurisdiction over many of PSCo’s activities, including regulation of retailrates and environmental matters.

 

***FERC Rules Implementing Energy Act*** –– As noted previously, theEnergy Act repealed PUHCA effective Feb. 8, 2006. In addition, the Energy Actrequired the FERC to conduct several rulemakings to adopt new regulations toimplement various aspects of the Energy Act. Since Aug. 2005, the FERC hascompleted or initiated the proceedings to modify its regulations on a number ofsubjects, including:

 

•                  Adopting new regulations toimplement the Energy Act repeal of PUHCA by establishing rules for accountingprocedures for holding company systems, including cost allocation rules fortransactions between companies within a holding company system;

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

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

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

•                  Adopting rules to implementchanges to the Public Regulatory Policy Act of 1978 (PURPA) to allow utilityownership of Qualifying Facilities (QFs) and strengthening the thermal energyrequirements for entities seeking to be QFs;

•                  Proposing rules that wouldallow a utility to seek to eliminate its mandatory QF power purchase obligationfor utilities in organized wholesale energy markets;

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

 

PSCo generally supportsthe regulations adopted or proposed by FERC to date, but cannot predict theultimate impact the new regulations will have on its operations or financialresults.

 

***Market-Based Rate Authority***— The FERCregulates the wholesale sale of electricity. In order to obtain market-basedrate authorization from the FERC, utilities such as PSCo are required to submitanalyses demonstrating that they did not have market power in the relevantmarkets. PSCo was previously granted market-based rate authority by the FERC. However,the FERC has subsequently modified its standards making it more difficult forutilities to demonstrate that they do not have market power and thus moredifficult to obtain market-based rate authority, particularly in their ownservice territories.

 

On Feb. 7, 2005, Xcel Energyon behalf of itself and the utility subsidiaries filed an updated market-poweranalysis that applied FERC’s new standards.This analysis demonstrated that PSCo did notpass the pivotal supplier analysis in its own control area and all adjacentmarkets or the market share analysis in its own control area.

 

In June 2005, the FERC initiated a proceedingto investigate PSCo’s market-based rate authority within its own control area. Therefund effective date that has been set as part of that investigation for suchsales is Aug. 12, 2005. The FERC required that Xcel Energy make a compliancefiling providing information, including information regarding the FERC’saffiliate abuse component of its market power analysis and the allegationsregarding that component made by an intervenor within 30 days of the date ofissuance of its order. The latter compliance filing was submitted onJuly 5, 2005.

 

On Aug. 1, 2005, PSCosubmitted a filing to withdraw its market-based rate authority with respect tosales within its control areas. As part of that filing, PSCo proposed to chargeexisting cost-based rates for sales into the PSCo control areas. In October2005, PSCo filed revised tariff sheets to reflect that limitation on itsmarket-based rate authority. The matter is pending before the FERC.

 

***ElectricTransmission Rate Regulation***— The FERC also regulates the rates charged and termsand conditions for electric transmission services. FERC policy encouragesutilities to turn over the functional control over their electric transmissionassets and the related responsibility for the sale of electric transmission servicesto an RTO. Each RTO separately files for 

 

8

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regional transmission tariff rates for approval byFERC. All members within that RTO are then subjected to those rates. PSCo iscurrently participating with other utilities in the development of an RTO.

 

**RatemakingPrinciples**

 

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

 

***Fuel, PurchasedEnergy and Conservation Cost Recovery Mechanisms*** — PSCo has several retail adjustmentclauses that recover fuel, purchased energy and resource costs:

 

•                  *Electric CommodityAdjustment (ECA)*—The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism thatcompares actual fuel and purchased energy expense in a calendar year to abenchmark formula. The ECA also provides for an $11.25 million cap on any costsharing over or under an allowed ECA formula rate. The formula rate is revisedannually and collected or refunded in the following year, if necessary. Thecurrent ECA mechanism will expire Jan. 1, 2007.

 

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

 

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

 

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

 

•                  *Demand-Side ManagementCost Adjustment (DSMCA)*— The DSMCA clause currently permits PSCo to recover DSM costs overfive years while non-labor incremental expenses and carrying costs associatedwith deferred DSM costs are recovered on an annual basis. PSCo also has alow-income energy assistance program. The costs of this energy conservation andweatherization program for low-income customers are recovered through theDSMCA.

 

PSCo recovers fuel and purchased energy costs from itswholesale customers through a fuel cost adjustment clause accepted for filingby the FERC.

 

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

 

•             an annual electric earnings test for 2004through 2006 with the sharing between customers and shareholders of earnings inexcess of a return on equity for electric operations of 10.75 percent;

 

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

 

•          a natural gas QSP thatprovides for bill credits to customers if PSCo does not achieve certainperformance targets relating to natural gas leak repair time and customerservice through 2007.

 

PSCo regularly monitors and records as necessary anestimated customer refund obligation under the PBRP. In April of each yearfollowing the measurement period, PSCo files its proposed rate adjustment underthe PBRP. The CPUC conducts proceedings to review and approve these rate adjustmentsannually.

 

•              In 2003, PSCo did not achieve theperformance targets for the QSP electric service unavailability measure or thecustomer complaint measure. Targets were met for the natural gas QSP. There wasno sharing of earnings for 2003, as

 

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PSCo establishednew rates in its general rate case.

 

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

 

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

 

***Pending and Recently Concluded Regulatory Proceedings –– FERC***

 

***PSCo and SPS FERC Transmission RateCase*****— On Sept. 2, 2004, XcelEnergy filed on behalf of PSCo and SPS an application to increase wholesaletransmission service and ancillary service rates within the Xcel Energy jointopen access transmission tariff (OATT). PSCo and SPS requested an increase inannual transmission service and ancillary services revenues of $6.1 million. Asa result of a settlement with certain PSCo wholesale power customers in 2003,their power sales rates would be reduced by $1.4 million. The net increase inannual revenues proposed was $4.7 million, of which $3.0 million isattributable to PSCo. The FERC suspended the filing and delayed the effectivedate of the proposed increase to June 1, 2005. The interim rates went intoeffect on June 1, 2005, subject to refund. On Feb. 6, 2006, the parties inthe proceeding submitted an uncontested offer of settlement that contains aformula rate for PSCo, a 10.5 percent rate of return on common equity, and thephased inclusion of PSCo’s 345 KV tie line costs in wholesale transmissionservice rates. The settlement results in a $1.6 million rate increase for PSCoeffective June 2005. The offer of settlement is pending FERC approval.

 

***California Refund Proceeding****—*A number of proceedings are pending before the FERC relating to the priceof sales into the California electricity markets from May 1, 2000 through June20, 2001. PSCo supplied energy to these markets during this period and has beenan active participant in the proceedings. In September 2005, PSCo reached an agreement with respect to these proceedingswith a group of California entities including: San Diego Gas & ElectricCompany, Pacific Gas and Electric Company, Southern California Edison Company,the California Department of Water Resources, the California ElectricityOversight Board, the California Public Utilities Commission and the CaliforniaAttorney General. In December 2005, the FERC approved the settlementwithout condition for the period of Jan. 1, 2000 through June 20, 2001. PSCowill pay approximately $5.5 million in cash and assign $1.8 million in accountsreceivable from the California Independent System Operator and the CaliforniaPower Exchange to the settling participants. In 2004, PSCo reservedapproximately $7 million related to this proceeding. The settlement, whichincludes no acknowledgment of wrongdoing by PSCo, avoids further costlylitigation and resolves all claims by PSCo against the settling participantsand by the settling participants against PSCo. While accounting forapproximately 90 percent of purchases in the California markets, the Californiautilities were not the only purchasers in those markets. However, thesettlement makes provision for other purchasers to opt into the settlement. Wedo not expect a material financial impact as resolution is reached with the non-settlingparties.

 

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

 

On June 25, 2003, theFERC issued 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.

 

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

 

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with market-based rates. Similarcompliance audits of other utilities have resulted in compliance orders and, incertain cases, civil penalties. On November 28, 2005, FERC issued an orderapproving an audit report that recommended certain operational changes butimposed no civil penalties.

 

***Pending and Recently Concluded Regulatory Proceedings–– CPUC***

 

***Tie Line Cost Recovery***–– On Sept. 20, 2001, theCPUC ruled that only 50 percent of the total cost of the high voltage directcurrent (HVDC) converter constructed by PSCo in Lamar, Colorado will be allowedin rate base. This facility is part of the 345 KV tie line transmissionfacilities connecting the PSCo and SPS systems. The CPUC decision resulted in areduction of potential PSCo rate base of approximately $16.7 million. On April7, 2005, PSCo filed an application with the CPUC proposing a mechanism thatwould leave half of the HVDC facility as a non-rate-base asset, but that wouldgenerate revenue to recover the cost of the non-rate-base asset on apay-as-you-go basis. The proposal would involve allocating half of any energyor fuel cost savings derived from buying electricity through the tie line ormaking sales through the tie line. Alternatively, PSCo stated that it would notobject to the entire HVDC facility being placed in rate base. A hearingexaminer for the CPUC issued a recommended decision on Nov. 16, 2005, thatreasoned that 100 percent of the HVDC converter be placed in rate base. PSCoexpects that the CPUC will act on the recommended decision in February 2006.

 

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

 

**Capacityand Demand**

 

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

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

 

 

 

The peak demand for PSCo’s system typically occurs inthe summer. The 2005 uninterrupted system peak demand for PSCo occurred on July21, 2005.

 

**EnergySources and Related Transmission Initiatives**

 

PSCo expects to meet its net dependable systemcapacity requirements through existing electric generating stations; purchasesfrom other utilities, independent power producers and power marketers;demand-side management options and phased expansion of existing generation atselect power plants.

 

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

 

PSCo also makes short-term firm and non-firm purchasesto replace generation from company-owned units that are unavailable due tomaintenance and unplanned outages, to provide the utility’s reserve obligation,to obtain energy at a lower

 

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

 

***PSCo Resource Plan***— PSCo estimates it will purchaseapproximately 36 percent of its total electric system energy needs for 2006 andgenerate the remainder with PSCo-owned resources.    Additional capacity has been secured under contract makingadditional energy available for purchase, if required. PSCo currently has undercontract or through owned generation, the resources necessary to meet itsanticipated 2006 load obligation.

 

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

 

On Dec. 17, 2004, the CPUCapproved a settlement agreement between PSCo and intervening parties concerningthe LCP. PSCo received a formal written decision of the CPUC in January 2005. TheCPUC approved PSCo’s plan to construct a 750-MW pulverized coal-fired unit atthe existing Comanche power station located near Pueblo, Colo.; transfer up to250 MW of capacity ownership from the 750-MW unit to Intermountain RuralElectric Association and Holy Cross Energy; and install additional emissioncontrol equipment on the two existing Comanche station units. PSCo hascompleted permitting the 750 MW Comanche 3 unit and began construction of thefacility in December 2005. In the approved settlement, PSCo also agreed toinvest in additional demand-side management and fund environmental programs inPueblo, Colo.

 

The approved settlementcontains a confidential construction cost cap for the Comanche 3 project (i.e.,the new unit and the emission controls on existing units 1 and 2) and aregulatory plan that authorizes PSCo to increase the equity component of its capitalstructure up to 60 percent in its 2006 rate case to offset the debt equivalentvalue of PSCo’s existing power purchase contracts and to otherwise improve PSCo’sfinancial strength. Depending upon PSCo’s senior unsecured debt rating duringthe time of PSCo general rates cases, the approved settlement permits PSCo toinclude various amounts of construction work in progress that are associatedwith the Comanche 3 project in rate base without an offset for allowance forfunds used during construction.

 

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

 

PSCo has received thefollowing permits or authorizations for construction and operation of Comanche3:

 

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

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

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

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

 

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

 

***Renewable Portfolio Standards —*** In November 2004, anamendment to the Colorado statutes was passed by referendum requiring implementationof a renewable energy portfolio standard for electric service. The new lawrequires PSCo to generate, or cause to be generated, a certain level ofelectricity from eligible renewable resources. Generation of electricity fromrenewable resources, particularly solar energy, may be a higher-costalternative to traditional fuels, such as coal and natural gas. Suchincremental costs are expected to be recovered from customers. On March 29,2005, the CPUC initiated a proceeding to determine the rules and regulationsrequired to implement the renewable portfolio standard. The CPUC receivednumerous rounds of comments with respect to proposed rules, and the CPUC heldhearings beginning in August 2005 regarding the rulemaking. The CPUC conductedoral deliberations in early October and determined, among other issues, thatcompliance with the renewable energy portfolio standard should be measuredthrough the acquisition of

 

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renewable energy creditseither with or without the accompanying renewable energy; that the utilitypurchaser owns the renewable energy credits associated with existing contractswhere the power purchase agreement is silent on this issue; that Coloradoutilities should be required to file implementation plans, thereby rejectingthe proposal to use an independent plan administrator; and the methodsutilities should use for determining the budget available for renewableresources. The CPUC issued proposed rules on Jan. 27, 2006. Final rules are expectedto become effective by the end of the first quarter 2006.

 

***Renewable EnergyStandard Adjustment (RESA) —***On December 1, 2005, PSCo filed with the CPUC toimplement a new 1-percent rider that would apply to each customer’s totalelectric bill generating approximately $22 million in annual revenue. Therevenues collected under the RESA will be used to acquire sufficient solarresources to meet the on-site solar system requirements in the Coloradostatutes. On Feb. 14, 2006, PSCo and the other parties to the case filed astipulation agreeing to reduce the RESA rider to 0.60% and to provide monthlyreports. Hearings were held on Feb. 17, 2006. A CPUC decision is pending. PSCoexpects the RESA rider will go into effect in early March 2006.

 

***Purchased TransmissionServices***—PSCo has contractual arrangements with regional transmission service providersto deliver power and energy to the subsidiaries’ native load customers, whichare retail and wholesale load obligations with terms of more than one year. Point-to-pointtransmission services typically include a charge for the specific amount oftransmission capacity being reserved, although some agreements may base chargeson the amount of metered energy delivered. Network transmission servicesinclude a charge for the metered demand at the delivery point at the time ofthe provider’s monthly transmission system peak, usually calculated as a12-month rolling average.

 

**Fuel Supply and Costs**

 

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

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

 

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

 

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

 

PSCo has contracted for coal suppliers to supply 100percent of the Cherokee, Cameo, and Valmont stations’ projected requirements in2006.

 

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

 

PSCo operates the jointly owned Hayden generatingplant in Colorado. All of Hayden’s coal requirements are under contract throughthe end of 2011. The coal will be trucked approximately 14 miles under atrucking contract effective through 2009 with an option to extend to the end of2011. In addition to Hayden, PSCo has partial ownership in the Craig generatingplant in Colorado. Approximately 70 percent of PSCo’s coal requirements forCraig are supplied by two long-term agreements. The remaining coal requirementsfor Craig are purchased on the spot market under short-term contracts. All ofthe 2006 expected requirements for Craig are under contract.

 

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

 

 

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

 

**CommodityMarketing Operations**

 

PSCo conducts various wholesale marketing operations,including the purchase and sale of electric capacity, energy and energy relatedproducts. Participation in short-term wholesale energy markets provides marketintelligence and information that supports the energy management of PSCo. PSCouses physical and financial instruments to minimize commodity price and creditrisk and hedge supplies and purchases. Engaging in short-term sales andpurchase commitments results in an efficient use of our plants and thecapturing of additional margins from non-traditional customers. PSCo also usesthese marketing operations to capture arbitrage opportunities created byregional pricing differentials, supply and demand imbalances and changes infuel prices. See additional discussion under Item 7A — Quantitative andQualitative Disclosures About Market Risk.

### ** **

**PSCoElectric Operating Statistics**

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

 

 

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**NATURALGAS UTILITY OPERATIONS**

 

**Summaryof Recent Regulatory Developments**

 

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 and transportation businesshas remained competitive as industrial and large commercial customers have theability to bypass the local natural gas utility through the construction ofinterconnections directly with interstate pipelines, thereby avoiding thedelivery charges added by the local natural gas utility.

 

As an LDC, PSCo provides unbundled transportation serviceto large customers. Transportation service does not have an adverse effect onearnings because the sales and transportation rates have been designed to makethem economically indifferent to whether natural gas has been sold andtransported or merely transported. However, some transportation customers mayhave greater opportunities or incentives to physically bypass the LDC’sdistribution system.

 

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

 

# **Ratemaking Principles**

 

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

 

***Purchased Gas andConservation Cost Recovery Mechanisms*******—****PSCohas a GCA mechanism, which allows PSCo to recover its actual costs of purchasedgas. The GCA is revised monthly to allow for changes in gas prices.

 

***Performance-basedRegulation and Quality of Service Requirements***— The CPUC established a combinedelectric and natural gas quality of service plan. See further discussion underItem 1, Electric Utility Operations.

 

**Pending and Recently Concluded RegulatoryProceedings**

 

***PSCoNatural Gas Rate Case*****— In 2005, PSCo filed for anincrease of $34.5 million in natural gas base rates in Colorado, based on areturn on equity of 11.0 percent with a common equity ratio of 55.49 percent.

** **

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

•                  Natural gas revenue increaseof $22 million;

•                  Return on common equity of10.5 percent;

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

•                  Common equity ratio of 55.49percent; and

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

 

# **Capability andDemand**

# ** **

PSCo projects peak day natural gas supply requirementsfor firm sales and backup transportation, which include transportationcustomers contracting for firm supply backup, to be 1,792,770 MMBtu. Inaddition, firm transportation customers hold 489,014 MMBtu for PSCo of capacitywithout supply backup. Total firm delivery obligation for PSCo is 2,281,784MMBtu per day. The maximum daily deliveries for PSCo in 2005 for firm andinterruptible services were 1,871,486 MMBtu on Dec. 7, 2005.

 

 

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

 

PSCo has closed the Leyden Storage Field and is in themonitoring phase of the abandonment process, which is expected to continueuntil December 2007. See further discussion at Note 12 to the ConsolidatedFinancial Statements.

 

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

 

**NaturalGas Supply and Costs**

 

PSCo actively seeks natural gas supply, transportationand storage alternatives to yield a diversified portfolio that providesincreased flexibility, decreased interruption and financial risk, andeconomical rates. This diversification involves numerous supply sources withvaried contract lengths.

 

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

 
| 2005 |   | $ | 8.01 |
|------|--------|---|------|
| 2004 |   | $ | 6.30 |
| 2003 |   | $ | 4.94 |

 

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

 

PSCo purchases natural gas by optimizing a balance oflong-term and short-term natural gas purchases, firm transportation and naturalgas storage contracts. During 2005, PSCo purchased natural gas fromapproximately 37 suppliers.

 

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

 

 

16

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**PSCoNatural Gas Operating Statistics**

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

 

 

17

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# **ENVIRONMENTALMATTERS**

# ** **

PSCo’s facilities are regulated by federal and stateenvironmental agencies. These agencies have jurisdiction over air emissions,water quality, wastewater discharges, solid wastes and hazardous substances.Various company activities require registrations, permits, licenses,inspections and approvals from these agencies. PSCo has received all 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 with all environmentalregulations applicable to its operations. However, it is not possible at thistime to determine when or to what extent additional facilities or modificationsof existing or planned facilities will be required as a result of changes toenvironmental regulations, interpretations or enforcement policies or,generally, what effect future laws or regulations may have upon its operations.For more information on environmental contingencies, see Note 12 to theConsolidated Financial Statements and the matter discussed below.

 

# **EMPLOYEES**

# ** **

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

 

**Item 1A — Risk Factors**

 

**Risks Associated with Our Business**

 

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

 

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

 

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

 

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

 

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

 

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

 

We engage in wholesalesales and purchases of electric capacity, energy and energy-related productsand, accordingly, are subject to commodity price risk, credit risk and otherrisks associated with these activities.

 

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

 

18

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do not completelyeliminate risks, including commodity price changes, market supply shortages,credit risk and interest rate changes. The impact of these variables couldresult in our inability to fulfill contractual obligations, significantlyhigher energy or fuel costs relative to corresponding sales commitments orincreased interest expense.

 

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

 

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

 

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

 

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns andmanages permanent life insurance policies on some of PSCo’s employees, known asCOLI. At various times, borrowings have been made against the cash values ofthese COLI policies and deductions taken on the interest expense on theseborrowings. The IRS has challenged the deductibility of such interest expensedeductions and has disallowed the deductions taken in tax years 1993 through1999.

 

We believe that the tax deduction of interest expense on the COLIpolicy loans is in full compliance with the law. Accordingly, PSRI has notrecorded any provision for income tax or related interest or penalties that maybe imposed by the IRS and has continued to take deductions for interest expenserelated to policy loans on its income tax returns for subsequent years.

 

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

 

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

 

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

 

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

 

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

 

19

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

 

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

 

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

 

• the site of a former federal uraniumenrichment facility;

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

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

 

In addition, we cannotassure you that existing environmental laws or regulations will not be revisedor that new laws or regulations seeking to protect the environment will not beadopted or become applicable to us or that we will not identify in the futureconditions that will result in obligations or liabilities under existingenvironmental laws and regulations. Revised or additional laws or regulationswhich result in increased compliance costs or additional operatingrestrictions, or currently unanticipated costs or restrictions under existinglaws or regulations, particularly if those costs are not fully recoverable fromour customers, could have a material adverse effect on our results ofoperations.

 

***Recession, grid disturbances, acts of war orterrorism could negatively impact our business.***

 

The consequences of a prolonged recession and adverse market conditionsmay include the continued uncertainty of energy prices and the capital andcommodity markets. We cannot predict the impact of any economic slowdown orfluctuating energy prices. However, such impact could have a material adverseeffect on our financial condition and results of operations.

 

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

 

The conflict in Iraq and any other military strikes or sustainedmilitary campaign may affect our operations in unpredictable ways and may causechanges in the insurance markets, force us to increase security measures andcause disruptions of fuel supplies and markets, particularly with respect tonatural gas and purchased energy. The possibility that infrastructurefacilities, such as electric generation, transmission and distributionfacilities, would be direct targets of, or indirect casualties of, an act ofwar may affect our operations. War and the possibility of further war may havean adverse impact on the economy in general. A lower level of economic activitymight result in a decline in energy consumption, which may adversely affect ourrevenues and future growth. Instability in the financial markets as a result ofwar may also affect our ability to raise capital.

 

Further, like other operators of major industrial facilities, ourgeneration plants, fuel storage facilities and transmission and distributionfacilities may be targets of terrorist activities that could result indisruption of our ability to produce or distribute some portion of our energyproducts. Any such disruption could result in a significant decrease inrevenues and significant additional costs to repair and insure our assets,which could have a material adverse impact on our financial condition andresults of operations. The potential for terrorism has subjected our operationsto increased risks and could have a material adverse effect on our business. Whilewe have already incurred increased costs for security and capital expendituresin response to these risks, we may experience additional capital and operatingcosts to implement security for our plants, such as additional physical plantsecurity and additional security personnel.

 

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

 

 

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***Reduced coal availability could negativelyimpact our business.***

** **

PSCo’s coal generationportfolio is heavily dependent on coal supplies located in the Powder RiverBasin of Wyoming.  Approximately 50percent of our annual coal requirement comes from this area. Coal generationcomprises approximately 85 percent of our annual generation.  In the first half of 2005, we beganexperiencing disruptions in our coal deliveries from the Powder River Basin,which continued throughout the year and are expected to continue at leastthrough part of 2006.  In response tothese disruptions PSCo mitigated the impact of reduced coal deliveries, bymodifying the dispatch of certain facilities to conserve coal inventories. Inaddition to the mitigation efforts, PSCo negotiated for the acquisition ofadditional, higher capacity rail cars and is working to upgrade certain coalhandling facilities with completion anticipated in the first half of 2006.  Despite these efforts, coal inventories havedeclined to below target levels. While we have secured under contract approximately99 percent of our anticipated 2006 coal requirements, we cannot predict withany certainty the likelihood of receiving the required coal.  This factor, combined with the currently lowinventory levels, has led us to continue coal mitigation.  While we are planning to rebuild inventoriesduring 2006, there is no guarantee that we will be able to do so.   The ultimate impact of coal availabilitycannot be fully assessed at this time, but could impact our futureresults.  

 

***Rising energy prices could negatively impactour business.***

 

A variety of market factorshave contributed to higher natural gas prices. The direct impact of these higher costs is generally mitigated for PSCothrough recovery of such costs from customers through various fuel costrecovery mechanisms.  However, higherfuel costs could significantly impact the results of operations, if requestsfor recovery are unsuccessful.  Inaddition, the higher fuel costs could reduce customer demand or increase baddebt expense, which could also have a material impact on PSCo’s results ofoperations.  Delays in the timing of thecollection of fuel cost recoveries as compared with expenditures for fuelpurchases are expected to have an impact on the cash flows of PSCo.  PSCo is unable to predict the future naturalgas prices or  the ultimate impact ofsuch prices on its results of operations or cash flows.

 

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

*** ***

Our electric and natural gas utilitybusinesses are seasonal businesses and weather patterns can have a materialimpact on our operating performance. Demand for electricity is often greater inthe summer and winter months associated with cooling and heating. Becausenatural gas is heavily used for residential and commercial heating, the demandfor this product depends heavily upon weather patterns throughout our serviceterritory and a significant amount of natural gas revenues are recognized inthe first and fourth quarters related to the heating season. Accordingly, ouroperations have historically generated less revenues and income when weatherconditions are milder in the winter and cooler in the summer. We expect thatunusually mild winters and summers would have an adverse effect on ourfinancial condition and results of operations.

 

***Our natural gas distribution activitiesinvolve numerous risks that may result in accidents and other operating risksand costs.***

*** ***

There are inherent in our natural gasdistribution activities a variety of hazards and operating risks, such asleaks, explosions and mechanical problems, that could cause substantialfinancial losses.  In addition, theserisks could result in loss of human life, significant damage to property,environmental pollution, impairment of our operations and substantial losses tous.  In accordance with customaryindustry practice, we maintain insurance against some, but not all, of theserisks and losses.  The occurrence of anyof these events not fully covered by insurance could have a material adverseeffect on our financial position and results of operations.  For our distribution lines located nearpopulated areas, including residential areas, commercial business centers,industrial sites and other public gathering areas, the level of damagesresulting from these risks is greater.

 

***Increasing costs associated with our definedbenefit retirement plans, health care plans and other employee-related benefitsmay adversely affect our results of operations, financial position, orliquidity.***

*** ***

We have defined benefit and postretirementplans that cover substantially all of our employees.  Assumptions related to future costs, returnon investments, interest rates and other actuarial assumptions have asignificant impact on our earnings and funding requirements.  Based on our assumptions at Dec. 31, 2005 andassuming continuation of the current federal interest rate relief beyond 2005,in order to maintain required funding levels for our pension plans, we do notexpect to make required future contributions. However, it is our practice to make voluntary contributions to maintainmore prudent funding levels than minimally required.  These amounts are estimates and may changebased on actual stock market performance, changes in interest rates and anychanges in governmental regulations. Therefore, contributions could be required in the future.

 

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In addition to the costs of our retirementplans, the costs of providing health care benefits to our employees andretirees have increased substantially in recent years.  We believe that our employee benefit costs,including costs related to health care plans for our employees and formeremployees, will continue to rise.  Theincreasing costs and funding requirements with our defined benefit retirementplan, health care plans and other employee benefits may adversely affect ourresults of operations, financial position, or liquidity.  

 

***Any reductions in our credit ratings couldincrease our financing costs and the cost of maintaining certain contractualrelationships.***

*** ***

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

 

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

 

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

 

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

 

We rely on Xcel Energy Services Inc., asubsidiary service company of Xcel Energy, for many administrativeservices.  If Xcel Energy were toexperience severe financial difficulties, it could temporarily disrupt theprovision of these services or require us to provide these services ourselves,at potentially greater cost.

 

***We are a wholly ownedsubsidiary of Xcel Energy.  Xcel Energycan exercise, within certain regulatory and other limitations and the limitationsprovided by corporate law, substantial control over our dividend policy andbusiness and operations and may exercise that control in a manner that may beperceived to be adverse to our interests.***

*** ***

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

 

•      ourpayment of dividends;

 

•      decisionson our financings and our capital raising activities;

 

•      mergersor other business combinations; and

 

•      ouracquisition or disposition of assets.

 

We have historically paidquarterly dividends to Xcel Energy.  In2005, 2004 and 2003 we paid $62.6 million, $243.9 million and $238.3 million ofdividends to Xcel Energy, respectively. Our board of directors could decide to increase dividends, within thelimitations of our approved capital structure, financial covenants and creditrating objectives, to Xcel Energy to support its cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay isalso limited to some extent by our indenture for our first mortgage bonds.

 

Any downgrade could also lead to higherlong-term borrowing costs.

 

**Item 1B — Unresolved SEC Staff Comments**

 

None

 

**Item 2**— **Properties**

 

Virtually all of theelectric utility plant of PSCo is subject to the lien of its first mortgagebond indenture.

 

Electric utility generatingstations: 

 

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

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(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.

 

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Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2005:

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

 

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

 

Natural gas utility mains atDec. 31, 2005:

 
| **Miles**    | ** ** |
|--------------|------------|
| Transmission |       | 2,300 |   |
| Distribution |       | 20,168 |   |

 

**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.

*** ***

***Hill, et al., vs. PSCo, et al.***- In lateOctober 2003, there were two wildfires in Colorado, one in Boulder Countyand the other in Douglas County.  Therewas no loss of life, but there was property damage associated with these fires.Parties asserted that trees falling into PSCo distribution lines may havecaused one or both fires.  OnJan. 14, 2004, an action against PSCo relating to the fire in BoulderCounty was filed in Boulder County District Court. There were 46 plaintiffs,including individuals and insurance companies, and three co-defendants,including PSCo.  The plaintiffs asserteddamages in excess of $35 million.  InJune 2005, PSCo reached a confidential settlement with all parties, aswell as the United States Forest Service and the Denver Public Schools,settling claims in connection with the fire in Boulder County.  The financial impact of the settlement wasnot material to PSCo.

 

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

 

•            maintenance of a minimum equity ratio of 30percent;

•            payment of dividends only from retainedearnings; and

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

 

With therepeal of the PUHCA, restrictions on the ability of PSCo to declare dividendsset out in that statute will no longer apply. However, dividends will besubject to the FERC’s jurisdiction under the Federal Power Act, which prohibitsthe payment of dividends out of capital accounts.

 

23

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The dividends declaredduring 2005 and 2004 were as follows:

 
| **Quarter Ended**

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

** **

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

 

This is omitted 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 may vary materially. Factors that could cause actual results todiffer materially include, 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, 2005.

 

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

 

**Results OfOperations**

 

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

 

***Electric Utility, Short-TermWholesale 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

 

24

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to fuel cost recovery mechanisms for retailcustomers, 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 is notassociated with PSCo’s generation assets or the energy and capacity purchasedto serve native load.

 

Margins from commoditytrading activity conducted at PSCo are partially redistributed to NorthernStates Power Company, a Minnesota corporation, and SPS, both wholly ownedsubsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA)approved by the FERC.  Margins received pursuant to the JOA arereflected as part of Base Electric Utility Revenue.  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 purchased power,transmission, broker fees and other related costs.  

 

The following table detailsthe revenue and margin for base electric utility, short-term wholesale andcommodity trading activities:

 
| **(Millions of Dollars)**                               | ** ** | **Base  Electric  Utility** | ** ** | **Short-Term  Wholesale** | ** ** | **Commodity  Trading** | ** ** | **Consolidated  Totals** | ** ** |
|---------------------------------------------------------|------------|-----------------------------|------------|---------------------------|------------|------------------------|------------|--------------------------|------------|
| **2005**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenue (excluding  commodity trading) |       | $                           | 2,486      |                      | $          | 17                     |       | $                        | —     |   | $ | 2,503 |   |
| Electric fuel and purchased power                       |       | (1,491                      | )          | (16                       | )          | —                 |       | (1,507                   | )          |
| Commodity trading revenue                               |       | —                      |       | —                    |       | 600                    |       | 600                      |       |
| Commodity trading costs                                 |       | —                      |       | —                    |       | (599                   | )          | (599                     | )          |
| Gross margin before operating expenses                  |       | $                           | 995        |                      | $          | 1                      |       | $                        | 1          |   | $ | 997 |   |
| Margin as a percentage of revenue                       |       | 40.0                        | %          | 5.9                       | %          | 0.2%                   |       | 32.1                     | %          |
|                                                    |       |                        |       |                      |       |                   |       |                     |       |
| **2004**                                                |       |                        |       |                      |       |                   |       |                     |       |
| Electric utility revenue (excluding  commodity trading) |       | $                           | 2,128      |                      | $          | 67                     |       | $                        | —     |   | $ | 2,195 |   |
| Electric fuel and purchased power                       |       | (1,181                      | )          | (62                       | )          | —                 |       | (1,243                   | )          |
| Commodity trading revenue                               |       | —                      |       | —                    |       | 472                    |       | 472                      |       |
| Commodity trading costs                                 |       | —                      |       | —                    |       | (473                   | )          | (473                     | )          |
| Gross margin before operating expenses                  |       | $                           | 947        |                      | $          | 5                      |       | $                        | (1         | ) | $ | 951 |   |
| Margin as a percentage of revenue                       |       | 44.5                        | %          | 7.5                       | %          | (0.2                   | )%         | 35.7                     | %          |
|                                                         |            |                             |            |                           |            |                        |            |                          |            |  |  |  |  |  |  |  |

 

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

 

***Base Electric Revenue***

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

 

25

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***Base Electric Margin***

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

*** ***

***Natural Gas Utility Margins*****— The following table details the change 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)**                | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------|------------|----------|------------|----------|------------|
| Natural gas utility revenue              |       | $        | 1,329      |     | $          | 1,074 |   |
| Cost of natural gas sold and transported |       | (1,032   | )          | (785     | )          |
| Natural gas utility margin               |       | $        | 297        |     | $          | 289 |   |

 

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

 

***Natural Gas Revenue***

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

 

Natural gasrevenue increased primarily due to higher gas costs, which are recoverd fromcustomers. 

 

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

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

 

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

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

 

26

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

 

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

 

Interest charges andfinancing costs decreased by approximately $9.8 million, or 6.5 percent, for2005 compared with 2004, primarily due to the refinancing of long-term debtwith lower coupon short-term debt and equity.

 

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

 

Income tax expense decreasedby approximately $2.6 million in 2005, compared with 2004.  The decrease was primarily due to lowerincome levels.  The effective tax ratewas 24.9 percent for the period ended Dec. 31, 2005, compared with 25.0 percentfor the same period in 2004.  

 

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

 

***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.

 

Certain contracts within thescope of these activities qualify for hedge accounting treatment under SFAS No.133 – “Accounting for Derivative Instruments and Hedging Activities,” asamended.

 

See Note 10 to the Consolidated FinancialStatements for a discussion of the various trading and hedging contracts ofPSCo.

 

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.

 

27

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VaR is calculated on aconsolidated basis. As of Dec. 31, 2005, the VaRs for the commodity tradingoperations were:

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

 

----

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

 

VaR is calculated on aconsolidated basis. As of Dec. 31, 2004, the VaRs for the commodity tradingoperations were:

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

 

----

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

 

***Interest Rate Risk —***PSCo is subject to the risk of 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 accruedon the underlying variable rate debt.  Hedges of fair value exposure are entered into to hedge thefair value of a recognized asset, liability or firm commitment.  Changes in the derivative fair values thatare designated as fair value hedges are recognized in earnings as offsets tothe changes in fair values of related hedged assets, liabilities or firmcommitments.  To test the effectivenessof such swaps, a hypothetical swap is used to mirror all the critical terms ofthe underlying debt and regression analysis is utilized to assess the effectivenessof the actual swap at inception and on an ongoing basis, if required.  The fair value of interest rate swaps isdetermined through counterparty valuations, internal valuations and brokerquotes.  There have been no materialchanges in the techniques or models used in the valuation of interest rateswaps during the periods presented.

 

AtDec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate onPSCo’s variable rate debt would impact pretax interest expense by approximately$1.9 million and $1.2 million, respectively.

 

***Credit Risk —***In addition to the risks discussed previously, PSCo is exposed 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 risk controlmechanisms when appropriate, such as letters of credit, parental guarantees,standardized master netting agreements and termination provisions that allowfor offsetting of positive and negative exposures. The credit exposure ismonitored and, when necessary, the activity with a specific counterparty islimited until credit enhancement is provided.

 

28

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

 

# **REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

Board of Directors andStockholder

Public Service Company ofColorado

 

We have audited theaccompanying consolidated balance sheets and statements of capitalization ofPublic Service Company of Colorado and subsidiaries (the “Company”) as ofDecember 31, 2005 and 2004, and the related consolidated statements ofincome, common stockholder’s equity and comprehensive income and cash flows foreach of the three years in the period ended December 31, 2005. Our auditsalso included the financial statement schedule listed in the Index at Item 15.These financial statements and financial statement schedule are theresponsibility of the Company’s management. Our responsibility is to express anopinion on the financial statements and financial statement schedule based onour 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. The Company is not required to have, nor were we engagedto perform, an audit of its internal control over financial reporting.  Our audits included consideration of internalcontrol over financial reporting as a basis for designing audit procedures thatare appropriate 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 subsidiaries as ofDecember 31, 2005 and 2004, and the results of their operations and theircash flows for each of the three years in the period ended December 31,2005, 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 statementstaken as a whole, presents fairly in all material respects the information setforth therein.

 

 

 
| /S/ DELOITTE  & TOUCHE LLP |   |
|--------------------------------|--------|
| Minneapolis,  Minnesota        |
| February 24,  2006             |

 

29

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**PUBLIC SERVICE CO. OF COLORADO**

**CONSOLIDATED STATEMENTS OF INCOME**

**(Thousands of Dollars)**

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

                

SeeNotes to Consolidated Financial Statements

 

30

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## ** **

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

**CONSOLIDATED STATEMENTS OFCASH FLOWS**

**(Thousandsof Dollars)**

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

  | $ | 151,424 |   | $ | 143,799 |   |
| Cash paid for income taxes (net of refunds received)                                          |       | $                      | (16,042    | )  | $ | 16,203 |   | $ | (17,589 | ) |

 

SeeNotes to Consolidated Financial Statements

 

31

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** **

**PUBLIC SERVICE CO. OF COLORADO**

**CONSOLIDATED BALANCE SHEETS**

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

 

SeeNotes to Consolidated Financial Statements

 

32

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

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

**AND COMPREHENSIVE INCOME**

**(Dollars in Thousands)**

 
| ** **                                                                             | ** ** | ** **        | ** ** | ** **      | ** ** | ** **        | ** ** | ** **        | ** ** | ** **         | ** ** | ** ** | ** ** |
|----------------------------------------------------------------------------------------|------------|-------------------|------------|-----------------|------------|-------------------|------------|-------------------|------------|--------------------|------------|------------|------------|
| ** **                                                                             | ** ** | ** **        | ** ** | ** **      | ** ** | ** **        | ** ** | ** **        | ** ** | **Accumulated**    | ** ** | ** ** | ** ** |
| ** **                                                                             | ** ** | ** **        | ** ** | ** **      | ** ** | ** **        | ** ** | **Other**         | ** ** | **Total**          | ** ** |
| ** **                                                                             | ** ** | **Common  Stock** | ** ** | **Premium  on** | ** ** | **Retained**      | ** ** | **Comprehensive** | ** ** | **Stockholder's**  | ** ** |
| ** **                                                                             | ** ** | **Shares**        | ** ** | **Amount**      | ** ** | **Common  Stock** | ** ** | **Earnings**      | ** ** | **Income  (loss)** | ** ** | **Equity** | ** ** |
| **Balance  at Dec. 31, 2002**                                                          |       | 100               |       | $               | —     |              | $          | 1,652,284         |       | $                  | 430,997    |       | $          | (104,819 | ) | $ | 1,978,462 |   |
| Net income                                                                             |       |              |       |            |       |              |       | 227,933           |       |               |       | 227,933    |       |
| Minimum pension liability adjustment, net  of deferred tax of $5,467 (see Note 8)      |       |              |       |            |       |              |       |              |       | 8,917              |       | 8,917      |       |
| Net derivative instrument fair value  changes during the period, net of tax of $10,753 |       |              |       |            |       |              |       |              |       | 16,188             |       | 16,188     |       |
| Unrealized gain — marketable securities,  net of tax of $176                      |       |              |       |            |       |              |       |              |       | 288                |       | 288        |       |
| Comprehensive income for 2003                                                          |       |              |       |            |       |              |       |              |       |               |       | 253,326    |       |
| Common dividends declared to parent                                                    |       |              |       |            |       |              |       | (237,316          | )     |               |       | (237,316   | )     |
| Contribution of capital by parent                                                      |       |              |       |            |       | 145,496           |       |              |       |               |       | 145,496    |       |
| **Balance at Dec. 31, 2003**                                                           |       | 100               |       | $               | —     |              | $          | 1,797,780         |       | $                  | 421,614    |       | $          | (79,426 | ) | $ | 2,139,968 |   |
| Net income                                                                             |       |              |       |            |       |              |       | 218,005           |       |               |       | 218,005    |       |
| Minimum pension liability adjustment, net  of deferred tax of $(4,202) (see Note 8)    |       |              |       |            |       |              |       |              |       | (7,317             | )          | (7,317     | )     |
| Net derivative instrument fair value  changes during the period, net of tax of $(947)  |       |              |       |            |       |              |       |              |       | (1,475             | )     | (1,475     | )     |
| Unrealized gain — marketable securities,  net of tax of $74                       |       |              |       |            |       |              |       |              |       | 121                |       | 121        |       |
| Comprehensive income for 2004                                                          |       |              |       |            |       |              |       |              |       |               |       | 209,334    |       |
| Common dividends declared to parent                                                    |       |              |       |            |       |              |       | (246,873          | )     |               |       | (246,873   | )     |
| Contribution of capital by parent                                                      |       |              |       |            |       | 184,123           |       |              |       |               |       | 184,123    |       |
| **Balance at Dec. 31, 2004**                                                           |       | 100               |       | $               | —     |              | $          | 1,981,903         |       | $                  | 392,746    |       | $          | (88,097 | ) | $ | 2,286,552 |   |
| Net income                                                                             |       |              |       |            |       |              |       | 211,417           |       |               |       | 211,417    |       |
| Minimum pension liability adjustment, net  of deferred tax of $(9,898) (see Note 8)    |       |              |       |            |       |              |       |              |       | (16,644            | )     | (16,644    | )     |
| Net derivative instrument fair value  changes during the period, net of tax of $(936)  |       |              |       |            |       |              |       |              |       | (1,482             | )     | (1,482     | )     |
| Unrealized gain — marketable securities,  net of tax of $71                       |       |              |       |            |       |              |       |              |       | 117                |       | 117        |       |
| Comprehensive income for 2005                                                          |       |              |       |            |       |              |       |              |       |               |       | 193,408    |       |
| Contribution of capital by parent                                                      |       |              |       |            |       | 202,029           |       |              |       |               |       | 202,029    |       |
| **Balance at Dec. 31, 2005**                                                           |       | 100               |       | $               | —     |              | $          | 2,183,932         |       | $                  | 604,163    |       | $          | (106,106 | ) | $ | 2,681,989 |   |
|                                                                                        |            |                   |            |                 |            |                   |            |                   |            |                    |            |            |            |  |  |  |  |  |  |  |  |  |

 

SeeNotes to Consolidated Financial Statements

 

33

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

**CONSOLIDATED STATEMENTS OF CAPITALIZATION**

**(Thousands of Dollars)**

** **
| ** **                                                                                             | ** ** | **Dec. 31** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-------------|------------|
| ** **                                                                                             | ** ** | **2005**    | ** ** | **2004** | ** ** |
| **Long-Term Debt**                                                                                     |       |        |       |   |   |
| First Mortgage Bonds, Series due:                                                                      |       |        |       |   |   |
| Nov. 1, 2005, 6.375%                                                                                   |       | —      |       | 134,500 |   |
| June 1, 2006, 7.125%                                                                                   |       | 125,000     |       | 125,000 |   |
| April 1, 2008, 5.625% (a)                                                                              |       | —      |       | 18,000 |   |
| Oct. 1, 2008, 4.375%                                                                                   |       | 300,000     |       | 300,000 |   |
| June 1, 2012, 5.5% (a)                                                                                 |       | —      |       | 50,000 |   |
| Oct. 1, 2012, 7.875%                                                                                   |       | 600,000     |       | 600,000 |   |
| March 1, 2013, 4.875%                                                                                  |       | 250,000     |       | 250,000 |   |
| April 1, 2014, 5.5%                                                                                    |       | 275,000     |       | 275,000 |   |
| April 1, 2014, 5.875% (a)                                                                              |       | —      |       | 61,500 |   |
| Sept. 1, 2017, 4.375% (a)                                                                              |       | 129,500     |       | — |   |
| Jan. 1, 2019, 5.1% (a)                                                                                 |       | 48,750      |       | 48,750 |   |
| Jan. 1, 2024, 7.25%                                                                                    |       | —      |       | 110,000 |   |
| Unsecured Senior A Notes, due July 15, 2009, 6.875%                                                    |       | 200,000     |       | 200,000 |   |
| Secured Medium-Term Notes, due March 5, 2007, 7.11%                                                    |       | 100,000     |       | 100,000 |   |
| Capital lease obligations, 11.2% due in installments through 2028                                      |       | 47,581      |       | 48,935 |   |
| Unamortized discount                                                                                   |       | (3,524      | )          | (5,870 | ) |
| Total                                                                                                  |       | 2,072,307   |       | 2,315,815 |   |
| Less current maturities                                                                                |       | 126,334     |       | 135,854 |   |
| Total long-term debt                                                                                   |       | $           | 1,945,973  |   | $ | 2,179,961 |   |
|                                                                                                   |       |        |       |   |   |
| **Common Stockholder’s Equity**                                                                   |       |        |       |   |   |
| Common stock — authorized 100 shares of $0.01 par value; outstanding  100 shares in 2005 and 2004 |       | $           | —     |   | $ | — |   |
| Capital in excess of par value on common stock                                                         |       | 2,183,932   |       | 1,981,903 |   |
| Retained earnings                                                                                      |       | 604,163     |       | 392,746 |   |
| Accumulated other comprehensive loss                                                                   |       | (106,106    | )          | (88,097 | ) |
| Total common stockholder’s equity                                                                 |       | $           | 2,681,989  |   | $ | 2,286,552 |   |

 

----

(a)      Pollution control financing.

 

SeeNotes to Consolidated Financial Statements

 

34

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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 wassubject 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.

 

On Aug. 8, 2005, President Bushsigned into law the Energy Act, significantly changing many federal energystatutes.  The Energy Act is expected tohave a substantial long-term effect on energy markets, energy investment, andregulation of public utilities and holding company systems by the FERC, the SECand the DOE.  The FERC was directed bythe Energy Act to address many areas previously regulated by other governmentalentities under the statutes and determine whether changes to such previousregulations are warranted.  The issuesthat the FERC has been required to consider associated with the repeal of thePUHCA include, but are not limited to, the expansion of the FERC authority toreview mergers and sales of public utility companies and the expansion of theFERC authority over the books and records of holding companies and publicutility companies previously governed by the SEC and the appropriate coststandard for the provision of non-power goods and services by service companies.  The FERC is in various stages of rulemakingon these and other issues.  Xcel Energycannot predict the impact the new rulemakings will have on its operations orfinancial results, if any.

 

***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 meters,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 theclauses and the recoverable costs incurred. In addition, PSCo presents itsrevenue, net of any excise or other fiduciary-type taxes or fees. A summary ofsignificant rate adjustment mechanisms follows:

 

•                     PSCogenerally recovers 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 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 Statement 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 contracts are recorded at fair marketvalue in accordance with SFAS 133, as amended. In addition, commodity-tradingresults include the impacts of any margin-sharing mechanisms. For moreinformation, see Note 10 to the Consolidated Financial Statements.

 

35

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***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 raterisks. These contracts consist mainly of commodity forwards, futures andoptions, index or fixed price swaps and basis swaps. For further discussion ofPSCo’s risk management and derivative activities see Note 10 to theConsolidated Financial 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 associated with regulatory obligations are recorded as regulatoryliabilities. Significant additions or improvements extending asset lives arecapitalized, while repairs and maintenance are charged to expense as incurred.Maintenance and replacement of items determined to be less than units ofproperty are charged to operating expenses as incurred. Property, plant andequipment also includes costs associated with other property held for futureuse.

 

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, 2005, 2004 and 2003 is 2.6 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 (forequity capital) and interest charges (for debt capital). AFDC amountscapitalized are included in PSCo’s rate base for establishing utility servicerates.

 

***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.  There is nolegal obligation associated with these nuclear operations from the past.

 

***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 if it is probable 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 as emission-controlequipment, the cost is capitalized and depreciated over the life of the plant,assuming the costs are recoverable in future rates or future cash flow.

 

Estimated remediation costs,excluding inflationary increases, are recorded. The estimates are based 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 PSCo’sshare of the cost. Any future costs of restoring sites where operation mayextend indefinitely are treated as a capitalized cost of plant retirement. Thedepreciation expense levels recoverable in rates include a provision forremoval expenses, which may include final remediation costs.  Removal costs recovered in rates areclassified as a regulatory liability.

 

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

 

Investment tax credits aredeferred and their benefits amortized over the estimated lives of the relatedproperty. Utility rate regulation also has created certain regulatory assetsand liabilities related to income taxes, which are summarized in Note 13 to theConsolidated Financial Statements. For more information on income taxes, seeNote 7 to the Consolidated Financial Statements.

 

36

----

 

*** ***

***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, asset retirement obligations,decommissioning, tax provisions, uncollectible amounts, environmental costs,unbilled revenues, jurisdictional fuel and energy cost allocations andactuarially determined benefit costs. The recorded estimates are revised whenbetter information is obtained or actual amounts are determinable. Thoserevisions can affect operating results. Each year the depreciable lives ofcertain plant assets are reviewed and revised, if appropriate.

 

***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.  

 

***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 are amortized over the remaining maturity periods of the relateddebt. PSCo’s deferred financing costs, net of amortization at Dec. 31, 2005 and2004 are $13.5 million and $15.1 million, respectively.

 

***Accounts Receivable and Allowancefor Uncollectibles*****—**Accountsreceivable are stated at the actual billed amount net of write-offs andallowance for uncollectibles.  PSCoestablishes an allowance for uncollectibles based on a reserve policy thatreflects its expected exposure to the credit risk of customers.

** **

**2. Short-TermBorrowings**

** **

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

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

** **

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

 

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

** **

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

 

37

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required state regulatoryapprovals.  The utility money pool allowsfor short-term loans between the utility subsidiaries and from the holdingcompany to the utility subsidiaries at market-based interest rates. The utilitymoney pool arrangement does not allow loans from the utility subsidiaries tothe holding company.  PSCo has approvalto borrow up to $250 million under the arrangement.  PSCo had no borrowings or loans outstandingunder the arrangement at Dec. 31, 2005. As a consequence of the repeal of PUHCA and the recent amendments to theFederal Power Act, it may be necessary for PSCo to submit its existing moneypool arrangement to FERC for its approval. PSCo is presently evaluating the situation.

 

**3.  Long-Term Debt**

** **

Effective Oct.14, 2005, PSCo discharged in accordance with its terms its Indenture, dated asof December 1, 1939, as supplemented, (1939 Indenture).  As a result, PSCo’s Indenture, dated as ofOct. 1, 1993, as supplemented, (1993 Indenture) becomes the first lien onPSCo’s electric properties subject to certain permitted liens as provided inthe 1993 Indenture.  PSCo’s outstandingfirst collateral trust bonds issued under the 1993 Indenture will, inaccordance with their terms, no longer be secured by bonds issued under the1939 Indenture and will become first mortgage bonds entitled to the benefit ofthe lien on PSCo’s electric properties under the 1993 Indenture and will berenamed “first mortgage bonds” to reflect this status.

 

***Credit Facilities*****—**AtDec. 31, 2005, PSCo had the following committed credit facilities available, inmillions of dollars:

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

----

* Net of credit facilityborrowings, issued and outstanding letters of credit and commercial paperborrowings.

 

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

 

As of Dec. 31, 2005, PSCo hadno direct borrowings on this line of credit, however this credit facility wasused to provide back-up support for PSCo commercial paper and letters ofcredit.  Also, $5.4 million of letters ofcredit were outstanding at Dec. 31, 2005, as discussed in Note 11 to theConsolidated Financial Statements, of which approximately $5.4 million wereoutstanding under the above credit facility and are included in the abovetable.

 

Maturities of long-term debtare:

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

 

**4.Preferred Stock**

 

PSCo has authorized theissuance of preferred stock.

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

 

**5.Mandatorily Redeemable Preferred Securities of Subsidiary Trusts**

 

PSCo Capital Trust I, 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.

 

38

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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, 2005:

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

 

PSCo’s current operationalassets include approximately 320 MWs of jointly owned generating capacity.PSCo’s share of operating expenses and construction expenditures are includedin the applicable utility accounts.  PSCobegan major construction on a new jointly owned 750-MW, coal-fired unit inPueblo, Colorado in January 2006.  Majorconstruction on the new unit, Comanche 3, is expected to be completed in2010.  PSCo is the operating agent underthe joint ownership agreement. PSCo is responsible for the issuance of its ownsecurities to finance its portion of the construction costs.

 

**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 following is atable reconciling such differences for the years ending Dec. 31:

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

 

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

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

 

39

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The components of deferredincome tax at Dec. 31 were:

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

 

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

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

** **

**8. BenefitPlans and Other Postretirement Benefits**

 

Pension and otherpostretirement disclosures below generally represent Xcel Energy consolidatedinformation unless specifically identified as being attributable to PSCo.

 

Xcel Energy offers variousbenefit plans to its benefit employees, including those of PSCo. Approximately56 percent of benefit employees are represented by several local labor unionsunder several collective-bargaining agreements. At Dec. 31, 2005, PSCo had 2,165bargaining employees covered under a collective-bargaining agreement, whichexpires 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:

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

 

40

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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 12.0 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 equityinvestments can increase the volatility in the return levels achieved bypension assets in any year. Investment returns in 2005, 2004 and 2003 exceededthe assumed levels of 8.75 percent, 9.0 percent and 9.25 percent, respectively.  Xcel Energy continually reviews its pensionassumptions.  In 2006, Xcel Energy willcontinue to use an investment return assumption of 8.75 percent.

*** ***

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

 

 

41

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During 2002, one of PSCo’spension plans became under funded, and at Dec. 31, 2005, had projected benefitobligations of $739.5 million, exceeding plan assets of $609.8 million. PSCohas recorded a minimum pension liability of $86.1 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 $120.4 million atDec. 31, 2005, due to the minimum pension liability for the under funded plan.All other Xcel Energy plans in the aggregate had plan assets of $2.5 billionand projected benefit obligations of $2.1 billion on Dec. 31, 2005.

 

***Cash Flows***—Cash funding requirements can be impacted by changes to actuarial assumptions,actual asset levels and other pertinent calculations prescribed by the fundingrequirements of income tax and other pension-related regulations. Theseregulations did not require cash funding in the years 2003 through 2005 forXcel Energy’s pension plans and are not expected to require cash funding in2006. PSCo elected to make voluntary contributions to its pension plan forbargaining employees of $9 million in 2004 and $14.7 million in 2005 andvoluntarily contributed $3.4 million to the NCE non-bargaining plans in2005.  PSCo expects to voluntarilycontribute between $15 and $30 million during 2006 to its pension plan forbargaining employees.

 

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

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

 

Pension costs include anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2006 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 also maintainsnoncontributory, defined benefit supplemental retirement income plans forcertain qualifying executive personnel. Benefits for these unfunded plans arepaid out of Xcel Energy’s 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 $6.2 million in 2005, $7.2 million in 2004 and $4.7 million in2003.

 

**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.Nonbargaining employees of the former NCE, who retired after June 30, 2003, areeligible to participate in the Xcel Energy health care program with no employersubsidy.

 

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

 

42

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Pensions,” Xcel Energyelected to amortize the unrecognized accumulated postretirement benefitobligation (APBO) on a straight-line basis over 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.

 

***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:

 

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

 

Xcel Energy bases 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. Investment-return volatility is notconsidered to be a material factor in postretirement health care costs.

 

43

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*** ***

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

 

Effective Dec. 31, 2004, XcelEnergy 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.  Xcel Energy bases its medical trendassumption on the long-term cost inflation expected in the health care market,considering the levels projected and recommended by industry experts, as wellas recent actual medical cost increases experienced by Xcel Energy’s retireemedical 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, 2005                         |       | $          | 62.9       |   |
| 1-percent decrease in APBO components at  Dec. 31, 2005                         |       | (52.4      | )          |
| 1-percent increase in service and interest  components of the net periodic cost |       | 5.0        |       |
| 1-percent decrease in service and interest  components of the net periodic cost |       | (4.1       | )          |
|                                                                                 |            |            |            |  |

 

The employer subsidy 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. additionalcash funding requirements are prescribed by certain state and federal rateregulatory authorities, as discussed previously. Xcel Energy expects tocontribute approximately $75 million during 2006.

 

44

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

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

 

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

 

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

 

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

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

 

45

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** **

** **

**10.Derivative Instruments**

** **

In the normal course of business, PSCo is exposed to a variety ofmarket risks.  Market risk is the potentialloss that may occur as a result of changes in the market or fair value of aparticular instrument or commodity.  PSCoutilizes, in accordance with approved risk management policies, a variety ofderivative 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 capacity, energy and energy-related products,and for various fuels used in the generation and natural gas utility operation.  Commodity risk also is managed through 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 each rate-regulatedoperation to the extent such exposure exists, as allowed by regulation.

 

***Short-Term Wholesaleand Commodity Trading Risk —*** PSCo conducts various short-term wholesaleand commodity trading activities, including the purchase and sale of electriccapacity, 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 guidelines and limitations as approved by ourrisk-management committee, which is made up of management personnel notdirectly involved 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 notqualifying for the normal purchases and normal sales exception, as defined bySFAS No. 133, are recorded at fair value. The classification of the fair valuefor these derivative instruments is dependent on the designation of aqualifying hedging relationship.  Thefair value of derivative instruments not designated in a qualifying hedgingrelationship is reflected in current earnings. This includes certain instruments used to mitigate market risk for PSCoand all instruments related to the commodity trading operations.  The designation of a cash flow hedge permitsthe classification of fair value to be recorded within Other ComprehensiveIncome, to the extent effective.  Thedesignation of a fair value hedge permits a derivative instrument’s gains orlosses to offset the related results of the hedged item in the ConsolidatedStatements of Income, to the extent effective.

 

SFAS No. 133 requires that the hedging relationship be highly effectiveand that a company formally designate a hedging relationship to apply hedgeaccounting.  PSCo formally documentshedging relationships, including, among other things, the identification of thehedging instrument and the hedged transaction, as well as the risk-managementobjectives and strategies for undertaking the hedged transaction.  PSCo also formally assesses, both atinception and on a regular basis, if required, whether the derivativeinstruments being used are highly effective in offsetting changes in either thefair value or cash flows of the hedged items.

 

Gains or losses on hedging transactions for the sales of energy orenergy-related products are primarily recorded as a component of revenue;hedging transactions for fuel used in energy generation are recorded as acomponent of fuel costs; hedging transactions for natural gas purchased forresale are recorded as a component of natural gas costs; and interest ratehedging transactions are recorded as a component of interest expense.  PSCo is allowed to recover in electric ornatural gas rates the costs of certain financial instruments acquired to reducecommodity 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**

# ** **

Theeffective portion of the change in the fair value of a derivative instrumentqualifying as a cash flow hedge is recognized in Other Comprehensive Income,and reclassified into earnings in the same period or periods during which thehedged transaction affects earnings.  Theineffective portion of a derivative instrument’s change in fair value isrecognized in current earnings.

 

***Commodity Cash Flow Hedges******—***PSCo enters intoderivative instruments to manage variability of future cash flows from changesin commodity prices.  These derivativeinstruments are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2005, PSCo had variouscommodity-related contracts classified as cash flow hedges extending through2009.  The fair value of these cash flowhedges is recorded in either Other Comprehensive Income or deferred as aregulatory asset or liability. This classification is based on the regulatoryrecovery mechanisms in place.  Amounts deferred in these accounts are recordedin earnings as the hedged purchase or sales transaction is settled. This couldinclude the purchase or sale of energy or energy-related products, the use ofnatural gas to generate electric energy or gas purchased for resale.

 

Asof Dec. 31, 2005, PSCo had no amounts in Accumulated Other Comprehensive Incomethat are expected to be recognized in earnings during the next 12 months as thehedged transactions settle.

 

PSCohad no ineffectiveness related to commodity cash flow hedges during the yearsended Dec. 31, 2005 and 2004, respectively.

 

***Interest Rate Cash Flow Hedges*** — PSCo entersinto****interest rate lockagreements, including treasury-rate locks and forward starting swaps thateffectively fix the yield or price on a specified treasury security for aspecific period.  These derivativeinstruments are designated as cash flow hedges for accounting purposes.

 

Asof Dec. 31, 2005, PSCo had net gains of approximately $1.5 million inAccumulated Other Comprehensive Income that it expects to recognize in earningsduring the next 12 months.

 

PSCohad no ineffectiveness related to interest rate cash flow hedges during theyears ended Dec. 31, 2005 and 2004, respectively.

 

***FinancialImpacts of Qualifying Cash Flow Hedges***— The impact of qualifyingcash flow hedges on PSCo’s Other Comprehensive Income, included in theConsolidated Statements of Stockholder’s Equity, is detailed in the followingtable:

 
| **(Millions of Dollars)**                                                           | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|
| Accumulated other  comprehensive loss related to hedges at Dec. 31, 2002            |       | $          | 1.0        |   |
| After-tax net unrealized  gains related to derivative accounted for as hedges       |       | 18.0       |       |
| After-tax net realized  gains on derivative transactions reclassified into earnings |       | (1.8       | )          |
| Accumulated other  comprehensive income related to hedges at Dec. 31, 2003          |       | $          | 17.2       |   |
|                                                                                |       |       |       |
| After-tax net unrealized  gains related to derivatives accounted for as hedges      |       | 8.6        |       |
| After-tax net realized  gains on derivative transactions reclassified into earnings |       | (10.1      | )          |
| Accumulated other  comprehensive income related to hedges at Dec. 31, 2004          |       | $          | 15.7       |   |
|                                                                                |       |       |       |
| After-tax net unrealized  gains related to derivatives accounted for as hedges      |       | 11.9       |       |
| After-tax net realized  gains on derivative transactions reclassified into earnings |       | (13.4      | )          |
| Accumulated other  comprehensive income related to hedges at Dec. 31, 2005          |       | $          | 14.2       |   |

 

**Fair Value Hedges**

 

The effective portion 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, 2005, PSCo had no fairvalue hedges.

 

**NormalPurchases or Normal Sales Contracts**

 

PSCo enters intocontracts for the purchase and sale of various commodities for use in its businessoperations.  SFAS No. 133

 

47

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requires a company toevaluate these contracts to determine whether the contracts arederivatives.  Certain contracts thatliterally meet the definition of a derivative may be exempted from SFAS No. 133as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for thepurchase or sale of something other than a financial instrument or derivativeinstrument that will be delivered in quantities expected to be used or soldover a reasonable period in the normal course of business.  In addition, normal purchases and normalsales contracts must have a price based on an underlying that is clearly andclosely related to the asset being purchased or sold.  An underlying is a specified interest rate,security price, commodity price, foreign exchange rate, index of prices orrates, or other variable, including the occurrence or nonoccurrence of aspecified event, such as a scheduled payment under a contract.

 

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, as amended.  None of thecontracts entered into within the commodity trading operations qualify for anormal designation.

 

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

 

The fair value of thecommodity trading contracts as of Dec. 31, 2005 and 2004 was $2.1 million and$(0.9) million, respectively.

 

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

 

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

 

**11. Financial Instruments**

 

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

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

 

The fair values of cashand cash equivalents, notes and accounts receivable and notes and accounts payableare 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 estimates presented are based oninformation available to management as of Dec. 31, 2005 and 2004. These fairvalue estimates have not been comprehensively revalued for purposes of theseConsolidated Financial Statements since that date, and current estimates offair values may differ significantly.

 

48

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PSCo provides a guarantee that guarantees payment orperformance under a specified agreement. As a result, PSCo’s exposure under the guarantee is based upon the netliability under the specified agreement. The guarantee issued by PSCo limits the exposure of PSCo to a maximumamount stated in the guarantee.  Theguarantee requires no liability to be recorded, contains no recourse provisionsand requires no collateral.  On Dec. 31,2005, PSCo had the following guarantee and exposure related to that guarantee:

 
| **(Millions of Dollars)  Nature of Guarantee**                                                          | ** ** | **Guarantor** | ** ** | **Guarantee  Amount** | ** ** | **Current  Exposure** | ** ** | **Term or Expiration Date** | ** ** | **Triggering  Event  Requiring  Performance** | ** ** | **Assets Held as   Collateral** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|---------------|------------|-----------------------|------------|-----------------------|------------|-----------------------------|------------|-----------------------------------------------|------------|---------------------------------|------------|
|                                                                                                    |       |          |       |                  |       |                  |       |                        |       |                                          |       |                            |       |
| Primarily bonds to guarantee restoration of sites that have been  disturbed to access utility equipment |       | PSCo          |       | $                     | 0.50       |                  | $          | (a                          | )          | 2006                                          |       | (b                              | )          | N/A |   |
|                                                                                                         |            |               |            |                       |            |                       |            |                             |            |                                               |            |                                 |            |  |  |

 

----

a)              The total exposure of thisindemnification cannot be determined. PSCo believes the exposure to be significantly less than the totalamount of the outstanding bonds.

b)             Failure of PSCo to perform under theagreement, which is the subject of the relevant bond.  In addition, per the indemnity agreementbetween PSCo and the various surety companies, the surety companies have thediscretion to demand collateral be posted.

 

# **Lettersof Credit**

# ** **

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

 

**12. Commitments and ContingentLiabilities**

 

***Tax Matters —*********PSCo’s wholly ownedsubsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent lifeinsurance policies, known as COLI policies, on some of PSCo’s employees. Atvarious times, borrowings have been made against the cash values of these COLIpolicies and deductions taken on the interest expense on these borrowings. TheIRS has challenged the deductibility of such interest expense deductions andhas disallowed the deductions taken in tax years 1993 through 1999.

 

In April 2004, Xcel Energyfiled a lawsuit against the government in the U.S. District Court for theDistrict of Minnesota to establish its right to deduct the policy loan interestexpense that had accrued during tax years 1993 and 1994.  After Xcel Energy had filed this suit, theIRS sent it two statutory notices of proposed deficiency of tax, penalty, andinterest for taxable years 1995 through 1999. Xcel Energy then timely filed two Tax Court petitions challenging thosenotices.  Xcel Energy anticipates thatthe dispute relating to its claimed interest expense deductions for tax years1993 and later will be resolved in the refund suit that is pending in theMinnesota federal district court and that the two Tax Court petitions will beheld in abeyance pending the outcome of the refund litigation.

 

On Oct. 12, 2005, the district court deniedXcel Energy’s motion for summary judgment on the ground that there weredisputed issues of material fact that required a trial to resolve.  At the same time, the district court deniedthe government’s motion for summary judgment that was based upon its contentionthat PSCo had lacked an insurable interest in the lives of the employeesinsured under the COLI policies.  Thedistrict court, however, granted Xcel Energy’s motion for partial summaryjudgment in its favor on the ground that PSCo did have the requisite insurableinterest.  The case is expected toproceed to trial and the litigation could take another two or three years orlonger.

 

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

 

49

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

 

*COLI DowChemical Court Decision*****- On Jan. 23,2006, the Sixth Circuit of the U.S. Court of Appeals issued an opinion in afederal income tax case involving the interest deductions for a COLI program atDow Chemical Company.  The Sixth Circuitdenied the tax deductions and reversed the decision of the trial court in thiscase.

 

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

 

•                     positivepre-deduction cash flows;

 

•                     mortalitygains; and

 

•                     thebuildup of cash values.

 

Ina split decision, the Sixth Circuit found that the Dow COLI plans possessednone of these indicators of economic substance. However, in Xcel Energy’s COLI case, the plans were projected to havesizeable pre-deduction cash flows, based upon the relevant assumptions whenpurchased.  Moreover, the plans presentedthe opportunity for mortality gains that were not eliminated either retroactivelyor prospectively.  Xcel Energy’s COLIplans had no provision for giving back any mortality gains that it mightrealize. In addition, Xcel Energy’s plans had large cash value increases thatwere not encumbered by loans during the first seven years of the policies.  Consequently, Xcel Energy believes thatthe facts and circumstances of its case are stronger than Dow’s case and continues tobelieve its case has strong merits.

 

***Leases*****— PSCo leases a variety of equipment andfacilities used in the normal course of business. Two of these leases qualifyas capital leases and are accounted for accordingly. The capital leasescontractually expire in 2025 and 2029. The assets and liabilities acquired under capital leases are recorded atthe lower of fair-market value or the present value of future lease paymentsand are depreciated over their actual contract term in accordance withpractices allowed by regulators. Depreciation of assets under capital leases is included in depreciationexpense for 2005 and 2004.

 

Following is a summary ofproperty held under capital leases:

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

 

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

 

Future commitments under operating leases are:

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

 

50

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Future commitments under PSCo’s two capital leasesare:

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

 

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

 

PSCo’s capital expenditure forecast includes the750-MW Comanche 3 coal-fired plant in Colorado. Comanche 3 is expected to cost approximately $1.35 billion, with majorconstruction starting in 2006 and finishing in 2010.  The Colorado commission has approved sharingone-third ownership of this plant with other parties.  Consequently, PSCo’s capital expenditureforecast includes $1 billion, approximately two-thirds of the total cost.

 

The capital expenditure programs of PSCo are subjectto continuing review and modification. Actual utility construction expendituresmay vary from the estimates due to changes in electric and natural gasprojected load growth, the desired reserve margin and the availability ofpurchased power, as well as alternative plans for meeting PSCo’s long-termenergy needs. In addition, PSCo’s ongoing evaluation of compliance with futurerequirements to install emission-control equipment, and merger, acquisition anddivestiture opportunities to support corporate strategies may impact actualcapital requirements.

 

***Fuel Contracts*****— PSCo has contracts providing for thepurchase and delivery of a significant portion of its current coal and naturalgas requirements. These contracts expire in various years between 2006 and2025. In addition, PSCo is required to pay additional amounts depending onactual quantities shipped under these agreements. The potential risk of loss,in the form of increased costs from market price changes in fuel, is mitigatedthrough the cost-rate adjustment mechanisms, which provide for pass through ofmost fuel, storage and transportation costs.

 

The estimated minimumpurchase obligation for PSCo under these contracts as of Dec. 31, 2005, is asfollows:

 

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

 

 

***Purchased PowerAgreements****—*PSCo has entered into agreements with utilities and other energysuppliers for purchased power to meet system load and energy requirements,replace generation from company-owned units under maintenance and duringoutages, and meet operating reserve obligations. PSCo has variouspay-for-performance contracts with expiration dates through the year 2027. Ingeneral, these contracts provide for capacity payments, subject to meetingcertain contract obligations and energy payments based on actual power takenunder the contracts. Certain contractual payment obligations are adjusted basedon indexes.  However, the effect of theseprice adjustments are mitigated through cost-of-energy rate adjustmentmechanisms.

 

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

 

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

 

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**Environmental Contingencies**

 

PSCo has been or iscurrently involved with the cleanup of contamination from certain hazardoussubstances at several sites. In many situations, PSCo is pursuing or intends topursue insurance claims and believes it will recover some portion of thesecosts through such claims. Additionally, where applicable, PSCo is pursuing, orintends to pursue, recovery from other potentially responsible parties andthrough the rate regulatory process.  Newand changing federal and state environmental mandates can also create addedfinancial liabilities for PSCo, which are normally recovered through the rateregulatory process.   To the extent anycosts are not recovered through the options listed above, PSCo would berequired to recognize an expense for such unrecoverable amounts in itsConsolidated Financial Statements.

 

***Site Remediation****—*PSCo must pay all or a portion of thecost to remediate sites where past activities of PSCo and some other partieshave caused environmental contamination. Environmental contingencies could arise from various situations includingthe following categories of sites:

 

•              the site of a former federal uranium enrichmentfacility,

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

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

 

PSCo records a liabilitywhen enough information is obtained to develop an estimate of the cost ofenvironmental remediation and revises the estimate as information isreceived.  The estimated remediation costmay vary materially.

 

To estimate the cost to remediate these sites,assumptions are made where facts are not fully known. For instance,  assumptions may be made about the nature 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..  At Dec. 31, 2005,the liability for the cost of remediating sites was estimated to be $1.2million, of which $0.7 million was considered to be a current liability.  Some of the cost of remediation may berecovered from:

 

•              insurance coverage;

•              other parties that have contributed to thecontamination; and

•              customers.

 

Neither the total remediation cost nor the finalmethod of cost allocation among all PRPs of the unremediated sites has beendetermined. Estimates have been recorded for PSCo’s future costs for thesesites.

 

###### ***Federal UraniumEnrichment Facility***

 

Approximately $0.5 million of the long-term liabilityfor PSCo relates to a DOE assessment for decommissioning a federal uraniumenrichment facility. This environmental liability does not include accrualsrecorded and collected from customers in rates for future nuclear fueldisposal.

 

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

 

***Fort Collins Manufactured Gas Plant Site*****—**Prior to 1926, Poudre Valley Gas Co., a predecessorof PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache laPoudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shutdown the MGP site and has sold most of the property.  An oily substance similar to MGP byproductswas discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, thecity of Fort Collins and Schrader Oil Co., under which PSCo performedremediation and monitoring work.   PSCohas substantially completed work at the site, with the exception of ongoingmaintenance and monitoring.  InMay 2005, PSCo filed a natural gas rate case with the CPUC requestingrecovery of clean-up costs at the Fort Collins MGP plant spent through March2005, which amounted to $6.2 million to be amortized over four years.  PSCo reached a settlement agreement with theparties in the case.  The CPUC approvedthe settlement agreement on Jan. 19, 2006, and the final order became effectiveon Feb. 3, 2006,

 

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withrates effective Feb. 6, 2006.

 

In April 2005, PSCobrought a contribution action against Schrader Oil Co. and related partiesalleging Schrader Oil Co. released hazardous substances into the environmentand these releases increased the migration and environmental impact of the MGPbyproducts at the site.  PSCo requesteddamages, including a portion of the costs PSCo incurred to investigate andremove contaminated sediments from the Cache la Poudre River.  On December 14, 2005 the court deniedSchrader’s request to dismiss the PSCo suit. On Jan. 3, 2006 Schrader filed a response to the PSCo complaint and acounterclaim against PSCo for its response costs under the CERCLA and under theResource Conservation and Recovery Act (RCRA). Schrader has alleged as part of its counterclaim an “imminent andsubstantial endangerment” of its property as defined by RCRA.  PSCo believes the allegations with respect toPSCo are without merit and will vigorously defend itself.

 

***Third Party andOther Environmental Site Remediation***

 

***Asbestos Removal*****—**Some of our facilities contain asbestos.Most asbestos will remain undisturbed until the facilities that contain it aredemolished or renovated.  PSCo hasrecorded an estimate for final removal of the asbestos as an asset retirementobligation.  See additional discussion ofasset retirement obligations elsewhere in Note 12.  It may be necessary to remove some asbestosto perform maintenance or make improvements to other equipment. The cost ofremoving asbestos as part of other work is immaterial and is recorded asincurred as operating expenses for maintenance projects, capital expendituresfor construction projects or removal costs for demolition projects.

 

***Leyden Gas StorageFacility*******— In February 2001, the CPUC approved PSCo’s plan to abandon the Leydennatural gas storage facility (Leyden) after 40 years of operation.  In July 2001, the CPUC decided that therecovery of all Leyden costs would be addressed in a future rate proceedingwhen all costs were known.  In 2003, PSCobegan flooding the facility with water, as part of an overall plan to convertLeyden into a municipal water storage facility owned and operated by the cityof Arvada, Colo.  In August 2003, theColorado Oil and Gas Conservation Commission (COGCC) approved the closure plan,the last formal regulatory approval necessary before conversion.  On Dec. 31, 2005, PSCo’s leases of the Leydenproperties were terminated and the city of Arvada took custody of thefacility.  PSCo is obligated to monitorthe site for two years after closure. As of Dec. 31, 2005, PSCo has incurredapproximately $5.7 million of costs associated with engineering buffer studies,damage claims paid to landowners and other initial closure costs.  PSCo has accrued an additional $0.2 millionof costs expected to be incurred through 2006 to complete the decommissioningand closure of the facility.  PSCo hasdeferred these costs as a regulatory asset.. In May 2005, PSCo filed a natural gas rate case with the CPUC requestingrecovery of Leyden costs totaling $4.8 million to be amortized over fouryears.  PSCo has reached a settlementagreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006, and thefinal order became effective on Feb. 3, 2006. PSCo believes that the additional $0.9 million of costs incurred may berecovered in a future case.

 

In December 2003, a homeowners associationpetitioned the EPA to assess the threat of a natural gas release from theLeyden facility pursuant to Section 105(d) of the CERCLA.  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 RCRAprogram.  On Nov. 24, 2004, the EPA sent a letter to the COGCCrequesting that the COGCC contact PSCo and request certain informationconcerning the closure.  To date noformal request has been received by PSCo.

 

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

 

***Other Environmental Requirements***

 

***Regional Haze Rules*** — On June 15, 2005, the EPAfinalized amendments to the July 1999 regional haze rules. These amendmentsapply to the provisions of the regional haze rule that require emissioncontrols, known as best available retrofit technology (BART), for industrialfacilities emitting air pollutants that reduce visibility by causing orcontributing to regional haze.  Some PSCogenerating facilities will be subject to BART requirements.

 

States must develop theirimplementation plans by December 2007. States will identify the facilities thatwill have to reduce emissions under BART and then set BART emissions limits forthose facilities.  Colorado is the firststate in Xcel Energy’s region to earnestly begin its BART rule development asthe first step toward the December 2007 deadline.  Xcel Energy is actively involved in thestakeholder process in Colorado and will also be involved as other states begintheir process.  Due to the uncertaintiesof the many decisions involved in this process, PSCo is not able to estimatethe cost impact to the company at this time.

 

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***Federal Clean Water Act***— The federal Clean WaterAct addresses the environmental impacts of cooling water intakes. InJuly 2004, the EPA published phase II of the rule that applies toexisting cooling water intakes at steam-electric power plants. Therule will require PSCo to perform additional environmental studies at afew power plants in Colorado to determine the impact the facilities may behaving on aquatic organisms vulnerable to injury.  If the studies determine the plants are notmeeting the new performance standards established by the phase II rule,physical and/or operational changes may be required at these plants.  It is not possible to provide an accurateestimate of the overall cost of this rulemaking at this time due to the manyuncertainties involved, including unresolved third party legal challenges tothe federal rule.  Based on the limitedinformation available, total capital and operating and maintenance costs toPSCo are estimated at approximately $0.5 million over the next five to 10years. Actual costs may be higher or lower depending on the final resolution oflegal challenges to the rule, as well as pending state and federal decisionsregarding interpretation of specific rule requirements.

 

***Notice of Violation*** — OnJuly 1, 2002, PSCo received a Notice of Violation (NOV) from the EPAalleging violations of the New Source Review (NSR) requirements of the CAA atthe Comanche and Pawnee plants in Colorado. The NOV specifically alleges thatvarious maintenance, repair and replacement projects undertaken at the plantsin the mid- to late-1990s should have required a permit under the NSR process.  PSCo believes it has acted in full compliancewith the CAA and NSR process. It believes that the projects identified in theNOV fit within the routine maintenance, repair and replacement exemptioncontained within the NSR regulations or are otherwise not subject to the NSRrequirements. PSCo also believes that the projects would be expresslyauthorized under the EPA’s NSR equipment replacement rulemaking promulgated inOctober 2003. On Dec. 24, 2003, the U.S. Court of Appeals for theDistrict of Columbia circuit stayed this rule while it considerschallenges to it. PSCo disagrees with the assertions contained in the NOV andintends to vigorously defend its position. As required by the CAA, the EPA metwith PSCo in September 2002 to discuss the NOV.

 

On March 10, 2005, theRocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo ofits intent to sue PSCo for alleged violations of the CAA at the Comancheplant.  The notice of intent to suealleges PSCo has violated the CAA’s Prevention of Significant Deteriorationregulations based on allegations that maintenance, repair and replacementprojects undertaken at the plants in the mid- to late-1990s should haverequired a permit under the NSR process. The allegations are the same as those presented in the NOV.  On June 9, 2005, Citizens for Clean Airand Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom providednotice of intent to sue PSCo for alleged violations of the CAA at the ComanchePlant.  The allegations in the notice ofintent to sue by CCAP and Ms. Glustrom are substantially identical tothose of RMELC.  PSCo believes theallegations with respect to PSCo are without merit and will vigorously defenditself in any suit which may be filed. Currently, PSCo is not able to estimate any potential loss.

 

# **Asset Retirement Obligations**

 

PSCo adopted Statement ofFinancial Accounting Standard SFAS No. 143 — “Accounting for Asset RetirementObligations” (SFAS No. 143) effective Jan. 1, 2003.  PSCo records future plant removal obligations as a liabilityat fair value with a corresponding increase to the carrying values of therelated long-lived assets. This liability will be increased over time byapplying the interest method of accretion to the liability, and the capitalizedcosts will be depreciated over the useful life of the related long-livedassets.  The recording of the obligationfor regulated operations has no income statement impact due to the deferral ofthe adjustments through the establishment of a regulatory asset pursuant toSFAS No. 71.

 

InMarch 2005, the Financial Accounting Standards Board (FASB) issued FASBInterpretation No. 47— “Accounting for Conditional Asset Retirement Obligations”(FIN No. 47) to clarify the scope and timing of liability recognition forconditional asset retirement obligations pursuant to SFAS No. 143.  The interpretation requires that a liabilitybe recorded for the fair value of an asset retirement obligation, if the fairvalue is estimable, even when the obligation is dependent on a futureevent.  FIN No. 47 further clarified thatuncertainty surrounding the timing and method of settlement of the obligationshould be factored into the measurement of the conditional asset retirementobligation rather than affect whether a liability should be recognized. PSCo implementedFIN No. 47 as of Dec. 31, 2005.  Includedin these financial statements is the recognition of a cumulative change inaccounting and disclosure of the liability on a pro forma basis.

 

***Recorded Asset Retirement Obligations (ARO)******—*** Assetretirement obligations have been recorded for steam production, electrictransmission and distribution systems and natural gas distributionsystems.  The steam production obligationincludes asbestos and ash-containment facilities.  The asbestos recognition associated with thesteam production includes certain plants at PSCo.  Generally, this asbestos abatement removalobligation originated in 1973 with the Clean Air Act, which applied to thedemolition of buildings or removal of equipment containing asbestos that canbecome airborne on removal.  Assetretirement obligations also have been recorded for PSCo steam production related to ash-containment facilities such asbottom ash ponds, evaporation ponds and solid waste landfills. The originationdate on the ARO recognition for ash-containment facilities at steam plants wasthe in-service date of various facilities.

 

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

 

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

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

 

 

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

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

 

***Indeterminate Asset Retirement Obligations —***PSCo has underground gas storagefacilities that have special closure requirements for which the final removaldate cannot be determined.

 

***Removal Costs***- PSCo accrues an obligationfor plant removal costs for generation, transmission and distributionfacilities.  Generally, the accrual offuture non-ARO removal obligations is not required.  However, long-standing ratemaking practicesapproved by applicable state and federal regulatory commissions have allowedprovisions for such costs in historical depreciation rates.  These removal costs have accumulated over anumber of years based on varying rates as authorized by the appropriateregulatory entities. Given the long periods over which the amounts were accruedand the changing of rates through time, PSCo has estimated the amount ofremoval costs accumulated through historic depreciation expense based oncurrent factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated futureremoval costs are considered Regulatory Liabilities under SFAS No. 71. Removal costsas of Dec. 31, 2005 and 2004 are $377 million and $383 million, respectively.

 

**Legal Contingencies**

 

In the normal course of business, PSCo is party toroutine claims and litigation arising from prior and current operations. PSCois actively defending these matters and has recorded a liability related to theprobable cost of settlement or other disposition when it can be reasonablyestimated.

 

***Carbon Dioxide Emissions Lawsuit***- On July 21, 2004, theattorneys general of eight states and New York City, as well as severalenvironmental groups, filed lawsuits in U.S. District Court for the SouthernDistrict of New York against five utilities, including Xcel Energy, to forcereductions 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

 

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effect on PSCo. The other utilities include American Electric PowerCo., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emittedwhenever fossil fuel is combusted, such as in automobiles, industrialoperations and coal- or gas-fired power plants. The lawsuits allege that CO2emitted by each company is a public nuisance as defined under state and federalcommon law because it has contributed to global warming. The lawsuits do notdemand monetary damages. Instead, the lawsuits ask the court to order eachutility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy andfour other utility companies filed a motion to dismiss the lawsuit, contending,among other reasons, that the lawsuit should be dismissed because it is anattempt to usurp the policy-setting role of the U.S. Congress and thepresident. On Sept. 19, 2005, the judge granted the defendants’ motion todismiss on constitutional grounds. Plaintiffs have filed a notice of appeal.

 

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.  Therealso is considerable debate regarding public policy for the approach that theUnited States should follow to address the issue.  The United Nations-sponsored Kyoto Protocol,which establishes greenhouse gas reduction targets for developed nations,entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify theprotocol and is opposed to legislative mandates, preferring a program based onvoluntary efforts and research on new technologies.  Xcel Energy is closely monitoring the issuefrom both scientific and policy perspectives. While it is not possible to know the eventual outcome, Xcel Energybelieves the issue merits close attention and is taking actions it believes areprudent to be best positioned for a variety of possible future outcomes.  Xcel Energy is participating in a voluntarycarbon management program and has established goals to reduce its volume ofcarbon dioxide emissions by 12 million tons by 2009 and to reduce carbonintensity by 7 percent by 2012.  Incertain jurisdictions, the evaluation process for future generating resourcesincorporates the risk of future carbon limits through the use of a carbon costadder or externality costs.  Xcel Energyalso is involved in other projects to improve available methods for managingcarbon.

 

***Payne et al. vs. PSCo et al.***- In lateOctober 2003, there was a wildfire in Boulder County, Colorado.  There was no loss of life, but there wasproperty damage associated with this fire. On Oct. 28, 2005, an action againstPSCo relating to this fire was filed in Boulder County District Court. Thereare 28 plaintiffs, including individuals, the City of Jamestown and one privatecorporation, and three co-defendants, including PSCo. Plaintiffs have assertedthat a tree falling into PSCo distribution lines may have caused the fire. Thislawsuit is in its early stages and PSCo intends to vigorously defend itselfagainst the claims asserted in this lawsuit . This lawsuit is not expected tohave a material financial impact and PSCo believes that its insurance coveragewill cover any liability in this matter.

 

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

 

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**13. Regulatory Assets and Liabilities**

 

PSCo’s financial statements are prepared in accordancewith the provisions of SFAS No. 71, as discussed in Note 1 to the ConsolidatedFinancial Statements. Under SFAS No. 71, regulatory assets and liabilities canbe created for amounts that regulators may allow to be collected, or mayrequire to be paid back to customers in future electric and natural gasrates.  Any portion of the business thatis not rate regulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or thebusiness of PSCo no longer allow for the application of SFAS No. 71 under GAAP,PSCO would be required to recognize the write-off of regulatory assets andliabilities in its statement of income. The components of unamortized regulatory assets and liabilities on thebalance sheets of PSCo are:

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

 

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

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

c)              These costs relate to unamortized costs for PSCo’sFort St. Vrain nuclear plant decommissioning.

 

**14. Segment and Related Information**

 

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

 

•       PSCo’s Regulated Electric Utility generates, transmitsand distributes electricity in Colorado. In addition, this segment includessales for resale and provides wholesale transmission service to variousentities in the United States. Regulated Electric Utility also includes PSCo’scommodity trading operations.

 

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

 

Revenues from operating segments not included aboveare below the necessary quantitative thresholds and are therefore included inthe All Other category. Those primarily include steam revenue, appliance repairservices and nonutility real estate activities.

 

To report net income for Regulated Electric andRegulated Natural Gas Utility segments, PSCo must assign or allocate all costsand certain other income. In general, costs are:

 

•       directly assigned wherever applicable;

•       allocated based on cost causation allocators whereverapplicable; or

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

 

57

----

 

The accountingpolicies of the segments are the same as those described in Note 1 to theConsolidated Financial Statements. These segments are managedseparately because the revenue streams are dependent upon regulated raterecovery which are separately determined for each segment.

 
| **(Thousands of Dollars)**                 | ** ** | **Regulated  Electric Utility** | ** ** | **Regulated  Natural  Gas Utility** | ** ** | **All  Other** | ** ** | **Reconciling  Eliminations** | ** ** | **Consolidated  Total** | ** ** |
|--------------------------------------------|------------|---------------------------------|------------|-------------------------------------|------------|----------------|------------|-------------------------------|------------|-------------------------|------------|
| **2005**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 2,504,028  |                                | $          | 1,329,034      |       | $                             | 33,501     |                    | $          | — |   | $ | 3,866,563 |   |
| Intersegment revenues                      |       | 263                             |       | 97                                  |       | —         |       | (360                          | )          | —                  |       |
| Total revenues                             |       | $                               | 2,504,291  |                                | $          | 1,329,131      |       | $                             | 33,501     |                    | $          | (360 | ) | $ | 3,866,563 |   |
| Depreciation and  amortization             |       | $                               | 179,774    |                                | $          | 52,009         |       | $                             | 6,619      |                    | $          | — |   | $ | 238,402 |   |
| Financing costs, mainly interest expense   |       | 108,824                         |       | 30,150                              |       | 2,241          |       | (969                          | )          | 140,246                 |       |
| Income tax expense  (benefit)              |       | 89,579                          |       | 23,112                              |       | (42,451        | )          | —                        |       | 70,240                  |       |
| Segment net income                         |       | $                               | 153,436    |                                | $          | 43,458         |       | $                             | 14,523     |                    | $          | — |   | $ | 211,417 |   |
| ** **                                 | ** ** | ** **                      | ** ** | ** **                          | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| **2004**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 2,194,628  |                                | $          | 1,073,989      |       | $                             | 27,825     |                    | $          | — |   | $ | 3,296,442 |   |
| Intersegment revenues                      |       | 180                             |       | 69                                  |       | —         |       | (249                          | )          | —                  |       |
| Total revenues                             |       | $                               | 2,194,808  |                                | $          | 1,074,058      |       | $                             | 27,825     |                    | (249       | ) | $ | 3,296,442 |   |
| Depreciation and  amortization             |       | $                               | 170,337    |                                | $          | 47,167         |       | $                             | 5,938      |                    | $          | — |   | $ | 223,442 |   |
| Financing costs, mainly interest expense   |       | 116,686                         |       | 32,033                              |       | 2,409          |       | (1,106                        | )          | 150,022                 |       |
| Income tax expense  (benefit)              |       | 80,578                          |       | 19,437                              |       | (27,159        | )          | —                        |       | 72,856                  |       |
| Segment net income                         |       | $                               | 152,870    |                                | $          | 58,513         |       | $                             | 6,622      |                    | $          | — |   | $ | 218,005 |   |
| ** **                                 | ** ** | ** **                      | ** ** | ** **                          | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **              | ** ** |
| **2003**                                   |       |                            |       |                                |       |           |       |                          |       |                    |       |
| Operating revenues from external customers |       | $                               | 2,117,790  |                                | $          | 883,052        |       | $                             | 23,271     |                    | $          | — |   | $ | 3,024,113 |   |
| Intersegment revenues                      |       | 251                             |       | 51                                  |       | —         |       | (302                          | )          | —                  |       |
| Total revenues                             |       | $                               | 2,118,041  |                                | $          | 883,103        |       | $                             | 23,271     |                    | $          | (302 | ) | $ | 3,024,113 |   |
| Depreciation and  amortization             |       | $                               | 178,243    |                                | $          | 43,048         |       | $                             | 5,494      |                    | $          | — |   | $ | 226,785 |   |
| Financing costs, mainly interest expense   |       | 123,246                         |       | 35,827                              |       | 8,769          |       | (8,546                        | )          | 159,296                 |       |
| Income tax expense  (benefit)              |       | 95,384                          |       | 20,500                              |       | (27,673        | )          | —                        |       | 88,211                  |       |
| Segment net income                         |       | $                               | 148,001    |                                | $          | 70,497         |       | $                             | 9,435      |                    | $          | — |   | $ | 227,933 |   |

 

**15. Related Party Transactions**

 

Xcel Energy Services Inc. provides management,administrative and other services for the subsidiaries of Xcel Energy,including PSCo. The services are provided and billed to each subsidiary inaccordance with Service Agreements approved by the SEC and executed by eachsubsidiary. Costs are charged directly to the subsidiary which uses the servicewhenever possible, and are allocated using an SEC approved method if theycannot be directly assigned.

 

Xcel Energy has establisheda utility money pool arrangement with the utility subsidiaries and receivedrequired state regulatory approvals.  See Note 2 for further discussion of thisborrowing arrangement.

 

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

 

CheyenneLight, Fuel and Power (Cheyenne), a former Xcel Energy subsidiary, purchasedall of its electricity requirements from PSCo. During 2004, Xcel Energy reachedan agreement to sell Cheyenne.  The salewas completed in January 2005.

 

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

 
| **(Thousands of Dollars)**                               | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|----------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Operating revenues:                                      |       |     |       |     |       |     |       |
| Electric utility                                         |       | $        | 2,378      |     | $          | 48,666   |       | $ | 55,855 |   |
| Natural gas utility                                      |       | —   |       | —   |       | 150      |       |
| Operating expenses:                                      |       |     |       |     |       |     |       |
| Other operations — paid to Xcel Energy Services Inc |       | 256,290  |       | 298,124  |       | 259,788  |       |
| Interest expense                                         |       | 725      |       | 886      |       | 1,103    |       |
|                                                          |            |          |            |          |            |          |            |  |  |  |

 

58

----

 

 

Accounts receivable and payable with affiliates atDec. 31, was:

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

 

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

 

**16. Summarized Quarterly FinancialData (Unaudited)**

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

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

 

----

a)                   Fourth quarter 2004 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.

 

**Item9**— **Changes in and Disagreements With Accountants onAccounting and****FinancialDisclosure**

 

During 2004 and 2005, andthrough the date of this report, there were no disagreements with theindependent public accountants for PSCo on accounting principles or practices,financial statement disclosures or audit scope or procedures.

 

**Item9A**— **Controls and Procedures**

 

**Disclosure Controls and Procedures**

** **

PSCo maintains a set of disclosure controls andprocedures designed to ensure that information required to be disclosed inreports that it files or submits under the Securities Exchange Act of 1934 isrecorded, processed, summarized and reported within the time periods specifiedin Securities and Exchange Commission rules and forms. As of the end of theperiod covered by this report, based on an evaluation carried out under thesupervision and with the participation of PSCo’s management, including theChief Executive Officer (CEO) and Chief Financial Officer (CFO), of theeffectiveness of its disclosure controls and procedures, the CEO and CFO haveconcluded that its disclosure controls and procedures are effective.

 

**Internal Control Over FinancialReporting**

 

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

 

59

----

 

**Item9B**— **Other Information**

 

None

 

**PART III**

 

Items 10, 11, 12 and 13 of Part III of Form 10-K havebeen omitted from this report for PSCo in accordance with conditions set forthin general instructions I (1) (a) and (b) of Form 10-K for wholly-ownedsubsidiaries.

 

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

** **

**Item11**— **Executive Compensation**

 

**Item12**— **Security Ownership of Certain Beneficial Owners andManagement**

 

**Item13**— **Certain Relationships and Related Transactions**

 

**Item14**— **Principal Accounting Fees and Services**

 

Information concerning fees paid to the principalaccountant for each of the last two years is contained in the Xcel Energy ProxyStatement for its 2006 Annual Meeting of Shareholders, which is incorporated byreference.

 

**PART IV**

 

**Item15**— **Exhibits, Financial Statement Schedules**

 

1.   Consolidated Financial Statements:

Reports of Independent Registered Public AccountingFirm **—**For the years ended Dec.31, 2005, 2004 and 2003.

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

Consolidated Statements ofCash Flows **—** For the three years ended Dec. 31, 2005, 2004 and2003.

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

 

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

 

3.         Exhibits

                  *Indicates incorporation byreference

                  +Executive CompensationArrangements and Benefit Plans Covering Executive Officers and Directors
| 2.01* |   | Merger Agreement and Plan of Reorganization dated  Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).                |
|-------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.01* |   | Amended and Restated Articles of Incorporation dated  July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).                                   |
| 3.02* |   | By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31,  1997, Exhibit 3(b)(1)).                                                                          |
| 4.01* |   | Indenture, dated as of Oct. 1, 1993, providing for  the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 —  Exhibit 4(a)). |
| 4.02* |   | Indentures supplemental to Indenture dated as of  Oct. 1, 1993:                                                                                    |

 
| **Dated as of** | ** ** | **Previous Filing:  Form; Date or  file no.** | ** ** | **Exhibit  No.** | ** ** | **Dated as of** | ** ** | **Previous Filing:  Form; Date or  file no.** | ** ** | **Exhibit  No.** | ** ** |
|-----------------|------------|-----------------------------------------------|------------|------------------|------------|-----------------|------------|-----------------------------------------------|------------|------------------|------------|
| ** **      | ** ** | ** **                                    | ** ** | ** **       | ** ** | ** **      | ** ** | ** **                                    | ** ** | ** **       | ** ** |
| ** **      | ** ** | ** **                                    | ** ** | ** **       | ** ** | ** **      | ** ** | ** **                                    | ** ** | ** **       | ** ** |
| Nov. 1, 1993    |       | S-3, (33-51167)                               |       | 4(b)(2           | )     | Aug. 15, 2002   |       | 10-Q, Sept. 30, 2002                          |       | 4.03             |       |
| Jan. 1, 1994    |       | 10-K, 1993                                    |       | 4(b)(3           | )     | Sept. 1, 2002   |       | 8-K, Sept. 18, 2002                           |       | 4.01             |       |
| Sept. 2, 1994   |       | 8-K, September 1994                           |       | 4(b              | )     | Sept. 15, 2002  |       | 10-Q, Sept. 30, 2002                          |       | 4.04             |       |
| May 1, 1996     |       | 10-Q, June 30, 1996                           |       | 4(b              | )     | March 1, 2003   |       | S-3, April 14, 2003  (333-104504)             |       | 4(b)(3           | )          |
| Nov. 1, 1996    |       | 10-K, 1996                                    |       | 4(b)(3           | )     | April 1, 2003   |       | 10-Q May 15, 2003  (001-03034                 |       | 4.02             |       |

 

60

----

 
| Feb. 1, 1997  |   | 10-Q, March 31, 1997 |   | 4(b    | )  | May 1, 2003    |   | S-4, June 11, 2003  (333-106011)      |   | 4.9   |   |
|---------------|--------|----------------------|--------|--------|---------|----------------|--------|---------------------------------------|--------|-------|--------|
| April 1, 1998 |   | 10-Q, March 31, 1998 |   | 4(b    | )  | Sept. 1, 2003  |   | 8-K, Sept. 2, 2003  (001-03280        |   | 4.02  |   |
|          |   |                 |   |   |    | Sept. 15, 2003 |   | Xcel 10-K, Mar. 15, 2004  (001-03034) |   | 4.100 |   |
|          |   |                 |   |   |    | Aug. 1, 2005   |   | PSCo 8-K, Aug. 18, 2005  (001-03280)  |   | 4.02  |   |

 
| 4.03*   |   | Indenture dated July 1, 1999, between Public Service  Co. of Colorado and The Bank of New York, providing for the issuance of  Senior Debt Securities and Supplemental Indenture dated July 15, 1999,  between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file  no. 001-03280) dated July 13, 1999).                                                                                                                                                       |
|---------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.04*   |   | Financing Agreement between Adams County, Colorado  and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County,  Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit  4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number  001-3280).                                                                                                                                                                                |
| 4.05*   |   | Registration Rights Agreement dated March 14, 2003  among Public Service Co. of Colorado , Bank One Capital Markets, Inc. and UBS  Warburg LLC (Exhibit 4.1 to Form S-4 (file no. 333-106011) dated June 11,  2003).                                                                                                                                                                                                                                                             |
| 4.06*   |   | $500,000,000 Credit Agreement among Public Service  Company of Colorado, as Borrower, the several lenders from time to time  parties hereto, Keybank National Association and USB Loan Finance LLC, as  documentation agents, The Bank of New York and Wells Fargo Bank, National  Association, as syndication agents and JPMorgan Chase Bank, N.A., as  administrative agent dated as of April 21, 2005 (Exhibit 4.02 to Form 10-Q  (file no. 001-03034) dated March 31, 2005). |
| 4.07    |   | $50,000,000.00 Revolving  Line of Credit Note between Public Service Company of Colorado and Wells Fargo Bank, National  Association, as of  December 1, 2005.                                                                                                                                                                                                                                                                                                                   |
| 4.08    |   | Amendment to the Credit Agreement dated April 21,  2005 between Public Service Company of Colorado and various lenders dated  Oct. 31, 2005.                                                                                                                                                                                                                                                                                                                                     |
| 10.01*+ |   | Xcel Energy Omnibus Incentive Plan (Exhibit A to  Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).                                                                                                                                                                                                                                                                                                                                                                        |
| 10.02*+ |   | Xcel Energy Executive Annual Incentive Award Plan  (Exhibit B to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).                                                                                                                                                                                                                                                                                                                                                         |
| 10.03*+ |   | Employment Agreement dated March 24, 1999, among  Northern States Power Co. (a Minnesota corporation), New Century Energies,  Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form  10-Q, (file no. 001-12927) dated March 31, 1999).                                                                                                                                                                                                                    |
| 10.04*+ |   | Amended and Restated Executive Long-Term Incentive  Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no.  001-03034) for the quarter ended March 31, 1998).                                                                                                                                                                                                                                                                                                     |
| 10.05*+ |   | Stock Equivalent Plan for Non-Employee Directors of  Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to  NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).                                                                                                                                                                                                                                                                             |
| 10.06*+ |   | Senior Executive Severance Policy, effective March  24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit  10(a)(2) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March  31, 1999).                                                                                                                                                                                                                                                  |
| 10.07*+ |   | New Century Energies Omnibus Incentive Plan,  (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927)  filed March 26, 1998.                                                                                                                                                                                                                                                                                                                                  |
| 10.08*+ |   | Directors’ Voluntary Deferral Plan (Exhibit 10(d)  (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec  31, 1998).                                                                                                                                                                                                                                                                                                                                   |
| 10.09*+ |   | Supplemental Executive Retirement Plan (Exhibit  10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated  Dec. 31, 1998).                                                                                                                                                                                                                                                                                                                                   |
| 10.10*+ |   | Salary Deferral and Supplemental Savings Plan for  Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K  (file no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                                                                                                                                                                     |
| 10.11*+ |   | Salary Deferral and Supplemental Savings Plan for  Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file  no. 001-12927) dated Dec. 31, 1998).                                                                                                                                                                                                                                                                                                           |
| 10.12*+ |   | Supplemental Executive Retirement Plan for Key  Management Employees, as amended and restated March 26, 1991 (Exhibit  10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).                                                                                                                                                                                                                                                                                      |
| 10.13*+ |   | Form of Key Executive Severance Agreement, as  amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K  (file no. 001-3280) dated Dec. 31, 1995).                                                                                                                                                                                                                                                                                                             |
| 10.14*+ |   | Supplemental Retirement Income Plan as amended July  23, 1991 (Exhibit 10(d) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31,  1996).                                                                                                                                                                                                                                                                                                                                       |
| 10.15*+ |   | Xcel Energy Senior Executive Severance and  Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4,  (file no. 333-112032) dated Jan. 21, 2004).                                                                                                                                                                                                                                                                                                            |
| 10.16*+ |   | Stock Equivalent Plan for Non-Employee Directors of  Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Form DEF-14A  (file no. 001-03034) dated Apr. 9, 2004).                                                                                                                                                                                                                                                                                                      |

 

61

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| 10.17*+ |   | Xcel Energy Nonqualified Deferred Compensation Plan  (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no.  001-03034) dated March 15, 2004).                                                                                                                                      |
|---------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.18*+ |   | Xcel Energy Non-employee Directors’ Deferred  Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no.  001-03034) dated March 15, 2004).                                                                                                                                         |
| 10.19*+ |   | Xcel Energy 401(k) Savings Plan, amended and  restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no.  333-112032) dated Jan. 21, 2004).                                                                                                                                             |
| 10.20*+ |   | New Century Energies, Inc. Employee Investment Plan  for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as  amended and restated effective Jan. 1, 2004 but with certain retroactive  amendments (Exhibit 10.20 to SPS Form S-4 (file no. 333-112032) dated Jan.  21, 2004). |
| 10.21*  |   | Form of Services Agreement between Xcel Energy  Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no.  001-03034) dated Nov. 16, 2000).                                                                                                                                          |
| 10.22*  |   | Securities Litigation Settlement Agreement as of  Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Form 8-K (file no.  001-03034) dated Jan. 14, 2005).                                                                                                                                 |
| 10.23*  |   | ERISA Actions Settlement Agreement as of Dec. 31,  2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Form 8-K (file no.  001-03034) dated Jan. 14, 2005).                                                                                                                                         |
| 10.24*  |   | Shareholder Derivative Action Settlement Agreement as  of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Form 8-K (file  no. 001-03034) dated Jan. 14, 2005).                                                                                                                         |
| 10.25*+ |   | Employment Agreement, effective Dec. 15, 1997,  between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel  Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).                                                                                              |
| 10.26*+ |   | Compensation and  reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.01  to Xcel Energy Form 10-Q (file no. 001-03034) dated Sept. 30, 2005.                                                                                                                              |
| 10.27*+ |   | Xcel Energy executive  officer salaries, annual bonus targets and long-term compensation awards for  2005 (Exhibit 10.27 to Form 10-K (file no. 001-03034) for the year ended Dec.  31, 2004).                                                                                                    |
| 10.28*+ |   | Amended Schedule of  Participants for Xcel Energy Senior Executive Severance and Change-in-Control  Policy (Exhibit 10.28 to Form 10-K (file no. 001-03034) for the year ended  Dec. 31, 2004).                                                                                                   |
| 10.29*+ |   | Xcel Energy Executive  Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06  to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                         |
| 10.30*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel  Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                                   |
| 10.31*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel  Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                                       |
| 10.32*+ |   | Xcel Energy Omnibus  Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel  Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                                   |
| 10.33*+ |   | Xcel Energy Omnibus 2005  Incentive Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25,  2005).                                                                                                                                                                                    |
| 10.34*+ |   | Xcel Energy Executive  Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034)  dated May 25, 2005).                                                                                                                                                                          |
| 10.35*+ |   | Xcel Energy Amended  Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit  10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).                                                                                                                                  |
| 10.36*+ |   | Xcel Energy Supplemental  Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034)  dated Dec. 13, 2005).                                                                                                                                                                        |
| 10.37+  |   | Xcel Energy executive  officer salaries, annual bonus targets and long-term compensation awards for  2006                                                                                                                                                                                         |
| 10.38+  |   | Amended Schedule of  Participants for Xcel Energy Senior Executive Severance and Change-in-Control  Policy                                                                                                                                                                                        |
| 10.39*  |   | Amended and Restated Coal Supply Agreement entered  into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between Public  Service Co. of Colorado and Amax Inc. on behalf of its division, Amax Coal  Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)).               |
| 10.40*  |   | First Amendment to Amended and Restated Coal Supply  Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between  Public Service Co. of Colorado and Amax Coal Co. (Form 10-K (file no.  001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)).                                       |
| 10.41*  |   | Proposed Settlement Agreement excerpts, as filed  with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3,  2004).                                                                                                                                                             |
| 10.42*  |   | Settlement Agreement among Public Service Co. of  Colorado and Concerned Environmental and Community Parties, dated Dec. 3,  2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).                                                                                            |
| 12.01   |   | Statement of Computation of Ratio of Earnings to  Fixed Charges.                                                                                                                                                                                                                                  |
| 23.01   |   | Consent of Independent Registered Public Accounting  Firm.                                                                                                                                                                                                                                        |
| 31.01   |   | Principal Executive Officer’s certification pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                                                                                      |
| 31.02   |   | Principal Financial Officer’s certification pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the  Sarbanes-Oxley Act of 2002.                                                                                                                                      |

 

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| 32.01 |   | Certification pursuant  to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002. |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------|
| 99.01 |   | Statement pursuant to  Private Securities Litigation Reform Act of 1995.                                                  |

 

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# **SCHEDULEII**

 

**PUBLICSERVICE COMPANY OF COLORADO**

**VALUATIONAND QUALIFYING ACCOUNTS**

**YearsEnded Dec. 31, 2005, 2004 and 2003**

**(Thousandsof Dollars)**

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

 

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1) Recovery of amountspreviously written off.

2) Principallyuncollectible accounts written off or transferred.

 

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## **SIGNATURES**

## ** **

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

 
| ** ** | ** ** | **PUBLIC SERVICE COMPANY OF COLORADO**     |
|------------|------------|--------------------------------------------|
| ** ** | ** ** | ** **                                 |
|       |       | /s/ BENJAMIN G.S. FOWKE III                |
|       |       | Benjamin G.S. Fowke III                    |
|       |       | Vice President and Chief Financial Officer |
|       |       | (Principal Financial Officer)              |

 

**February 24, 2006**

 

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

 
| /s/ PATRICIA K. VINCENT                              |   |                                         | /s/ GARY R. JOHNSON  |   |
|------------------------------------------------------|--------|----------------------------------------------|----------------------|--------|
| Patricia K. Vincent                                  |   | Gary R. Johnson                              |
| President, Chief Executive Officer and Director      |   | Vice President, General Counsel and Director |
| (Principal Executive Officer)                        |   |                                         |
|                                                 |   |                                         |
| /s/ TERESA S. MADDEN                                 |   |                                         | /s/ RICHARD C. KELLY |   |
| Teresa S. Madden                                     |   | Richard C. Kelly                             |
| Vice President and Controller                        |   | Chairman and Director                        |
| (Principal Accounting Officer)                       |   |                                         |
|                                                 |   |                                         |
| /s/ BENJAMIN G.S. FOWKE III                          |   |                                         | /s/ PAUL J. BONAVIA  |   |
| Benjamin G.S. Fowke III                              |   | Paul J. Bonavia                              |
| Vice President, Chief Financial Officer and Director |   | Vice President and Director                  |
| (Principal Financial Officer)                        |   |                                         |
|                                                 |   |                                         |
| /s/ CYNTHIA L. LESHER                                |   |                                         |                 |
| Cynthia L. Lesher                                    |   |                                         |
| Vice President and Director                          |   |                                         |

 

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**SUPPLEMENTAL INFORMATION TO BEFURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BYREGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THEACT**

 

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

 

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