**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

** **

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** **

**FORM 10-K**

** **
| **(Mark One)**                                                                                                                                                 |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **x**                                                                                                                                                          | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF  THE SECURITIES EXCHANGE ACT OF 1934** |
|                                                                                                                                                           |   |
| **For the  fiscal year ended December 31, 2006**                                                                                                               |
|                                                                                                                                                           |   |
| **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 NUMBER001-03280**

** **

**PUBLIC SERVICE COMPANY OF COLORADO**

(Exact name of registrant as specified in its charter)

 

| **Colorado**                              |   | **84-0296600**       |
|-------------------------------------------|--------|----------------------|
| (State or other  jurisdiction of          |   | (I.R.S. Employer     |
| incorporation or  organization)           |   | Identification  No.) |
|                                      |   |                 |
| **1225  17th Street**                     |
| **Denver,  Colorado 80202**               |
| (Address of  principal executive offices) |
| (Zip Code)                                |

 

**(303) 571-7511**

(Registrant’s telephone number, including area code)

 

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

 

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

 

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined by Rule 405 of the Securities Act. o Yes or No ý

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) of theExchange Act. o Yes orNo ý

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

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor 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 Large accelerated filer o Accelerated filer ýNon-accelerated filer

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

As of Feb. 26, 2007, 100 shares of common stock, parvalue $0.01 per share, were outstanding, all of which were held by Xcel EnergyInc., a Minnesota corporation.

**DOCUMENTSINCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2007 Proxy Statement, to be filedsubsequently**

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

 

 

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**INDEX**
|                                                                                                                                   |
|-----------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                              |
| **PART I**                                                                                                                        |
| Item 1  — Business                                                                                                           |
| DEFINITIONS                                                                                                                       |
| COMPANY OVERVIEW                                                                                                                  |
| ELECTRIC UTILITY  OPERATIONS                                                                                                      |
| Summary of  Recent Regulatory Developments                                                                                        |
| General Electric  Utility Pending Regulatory Matters                                                                              |
| Ratemaking Principles                                                                                                             |
| Capacity and Demand                                                                                                               |
| Energy Sources                                                                                                                    |
| Fuel Supply and Costs                                                                                                             |
| Trading  Operations                                                                                                               |
| Electric  Operating Statistics                                                                                                    |
| NATURAL GAS UTILITY  OPERATIONS                                                                                                   |
| Summary of  Recent Regulatory Developments                                                                                        |
| Ratemaking Principles                                                                                                             |
| Capability and Demand                                                                                                             |
| Natural Gas Supply and  Costs                                                                                                     |
| Natural Gas  Operating Statistics                                                                                                 |
| ENVIRONMENTAL MATTERS                                                                                                             |
| EMPLOYEES                                                                                                                         |
| Item  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, Related Stockholder Matters and Issuer  Purchases of Equity Securities |
| 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, Executive Officers, and Corporate Governance                                                           |
| Item 11 — Executive  Compensation                                                                                            |
| Item 12 —  Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters                   |
| Item 13 —  Certain Relationships, Related Transactions, and Director Independence                                            |
| Item 14 —  Principal Accounting Fees and Services                                                                            |
|                                                                                                                              |
| **PART IV**                                                                                                                       |
| Item 15 —  Exhibits, Financial Statement Schedules                                                                           |
| ** **                                                                                                                        |

**SIGNATURES**

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

 

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**PART I**

**Iteml**— **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***               |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 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                                                        |   | Retail electric commodity adjustment. The ECA,  effective Jan. 1, 2004, is an incentive adjustment mechanism that compares  actual fuel and purchased energy expense in a calendar year to a benchmark  formula. The ECA also provides for an $11.25 million cap on any cost sharing  over or under an allowed ECA formula rate. The current ECA mechanism expired  Dec. 31, 2006. Effective Jan. 1, 2007 the ECA has been modified to include an  incentive adjustment to encourage efficient operation of base load coal  plants and encourage cost reductions through purchases of economical  short-term energy. The total incentive payment to PSCo in any calendar year  will not exceed $11.25 million. The ECA mechanism will be revised quarterly  and interest will accrue monthly on the average deferred balance. The ECA  will expire at the earlier of rates taking effect after Comanche 3 is placed  in service or Dec. 31, 2010. |
| 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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |

 

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|                                     |   | 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.                                                                                                                                                                                                                                                                                                                                                                                                |
|-------------------------------------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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 not included in the  determination of PSCo’s base electric rates or other recovery mechanisms.  This clause expired in 2006. A new PCCA clause will become effective Jan. 1,  2007 permits recovery from retail customers for all purchased capacity  payments to power suppliers. Capacity charges are not included in PSCo’s base  electric rates or other recovery mechanisms. |
| QSP                                 |   | Quality of service plan. Provides for bill credits  to retail customers if the utility does not achieve certain operational  performance targets and/or specific capital investments for reliability. The  current QSP for PSCo and SPS electric utility expired in 2006. A new QSP for  the PSCo electric utility provides for bill credit to customers based upon  operational performance standards through Dec. 31, 2010.The QSP for the PSCo  gas utility expires December 2007.                                                                                          |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

 

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|                   |   | Clarified the terms clearly and closely related to  normal purchases and sales contracts, as included in SFAS No. 133, as  amended.                                                                                                                                                            |
|-------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| JOA               |   | Joint operating agreement among the Utility  Subsidiaries                                                                                                                                                                                                                                      |
| LDC               |   | Local distribution company. A company or division  that obtains the major portion of its revenues from the operations of a  retail distribution system for the delivery of electricity or natural gas for  ultimate consumption.                                                               |
| LIBOR             |   | London Interbank Offered Rate                                                                                                                                                                                                                                                                  |
| LNG               |   | Liquefied natural gas. Natural gas that has been  converted to a liquid by cooling it to — 260 degrees Fahrenheit.                                                                                                                                                              |
| mark-to-market    |   | The process whereby an asset or liability is  recognized at fair value and the change in the fair value of that asset or  liability is recognized in current earnings in the Consolidated Statements of  Operations or in Other Comprehensive Income within equity during the current  period. |
| MGP               |   | Manufactured gas plant                                                                                                                                                                                                                                                                         |
| MISO              |   | Midwest Independent Transmission System Operator                                                                                                                                                                                                                                               |
| native load       |   | The customer demand of retail and wholesale  customers whereby a utility has an obligation to serve: e.g., an obligation  to provide electric or natural gas service created by statute or long-term  contract.                                                                                |
| natural gas       |   | A naturally occurring mixture of hydrocarbon and  non-hydrocarbon gases found in porous geological formations beneath the  earth’s surface, often in association with petroleum. The principal  constituent is methane.                                                                   |
| nonutility        |   | All items of revenue, expense and investment not  associated, either by direct assignment or by allocation, with providing  service to the utility customer.                                                                                                                                   |
| OMOI              |   | FERC Office of Market Oversight and Investigations                                                                                                                                                                                                                                             |
| PBRP              |   | Performance-based regulatory plan. An annual  electric earnings test, an electric quality of service plan and a natural gas  quality of service plan established by the CPUC.                                                                                                                  |
| PUHCA             |   | Public Utility Holding Company Act of 1935. Enacted  to regulate the corporate structure and financial operations of utility  holding companies.                                                                                                                                               |
| PUHCA 2005        |   | Public Utility Holding Company Act of 2005.  Successor to the Public Utility Holding Company Act of 1935. Eliminates most  federal regulation of utility holding companies. Transfers other regulatory  authority from the SEC to FERC.                                                        |
| 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.                                                |

 

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

 

 

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**COMPANY OVERVIEW**

PSCowas incorporated in 1924 under the laws of Colorado.  PSCo is an operating utility engagedprimarily in the generation, purchase, transmission, distribution and sale ofelectricity.  PSCo also purchases,transports, distributes and sells natural gas to retail customers andtransports customer-owned natural gas. PSCo serves approximately 1.3 million electric customers andapproximately 1.3 million natural gas customers in Colorado.  The wholesale customers served by PSCocomprised approximately 22 percent of the total Kwh sales in 2006.  All of PSCo’s retail electric operatingrevenues were derived from operations in Colorado during 2006.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., whichowns certain real estate interests for PSCo; PSRI, which owns and managespermanent life insurance policies on certain current and former employees; andGreen and Clear Lakes Company, which owns water rights.  PSCo also holds a controlling interest inseveral other relatively small ditch and water companies.

**ELECTRIC UTILITY OPERATIONS**

**Overview**

***Utility IndustryGrowth***— PSCo intends to focus on growing throughinvestments in electric and natural gas rate base to meet growing customerdemands and to maintain or increase reliability and quality of service tocustomers.  PSCo plans to continue tofile rate cases with state and federal regulators to earn a return on itsinvestment and recover costs of operations.

***Utility Restructuring and Retail Competition***—The structure of the utility industry has been subject to change.  Merger and acquisition activity had beensignificant as utilities combined to capture economies of scale or establish astrategic niche in preparing for the future. The FERC has implemented wholesale electric utility competition, and thewholesale customers of Xcel Energy’s utility subsidiaries can purchase fromcompeting wholesale suppliers and use the transmission systems of the utilitysubsidiaries on a comparable basis to the utility subsidiaries’ use to servetheir native load.  Beginning in the late1990s, many states began studying or implementing some form of retail electricutility competition.

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

**Summary of Recent Federal RegulatoryDevelopments**

The FERC has jurisdiction over rates for electrictransmission service in interstate commerce and electric energy sold atwholesale, hydro facility licensing, natural gas transportation, 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. In addition to the matters discussed below,see Note 11 to the Consolidated Financial Statements for a discussion of otherregulatory matters.

***FERC Rules Implementing Energy PolicyAct of 2005 (Energy Act)*** - The Energy Act repealed PUHCAeffective Feb. 8, 2006.  Inaddition, the Energy Act required the FERC to conduct several rulemakings toadopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completedor initiated the proceedings to modify its regulations on a number of subjects,including:

·         Adoptingnew regulations by establishing rules for accounting procedures forholding company systems, including cost allocation rules for transactionsbetween companies within a holding company system;

·         Adoptingnew regulations to implement changes to the FERC’s merger and asset transferauthority;

·         Adoptingnew “market manipulation regulations” prohibiting any “manipulative or deceptivedevice or contrivance” in wholesale natural gas and electricity commodity andtransportation or transmission markets and interpreting this standard in amanner consistent with Rule 10b-5 of the SEC; violations are subject topotential civil penalties of up to $1 million per day;

·         Adoptingregulations to establish a national Electric Reliability Organization (ERO) toreplace the voluntary North American Electric Reliability Council (NERC)structure, and requiring the ERO to establish mandatory reliability standardsand imposition of financial or other penalties for violations of adoptedstandards.  The FERC has issued proposedrules to make 83 ERO reliability standards mandatory and subject to potentialfinancial penalties for non-compliance to be effective June 1, 2007;

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·         Adoptingrules to implement changes to the Public Utility Regulatory Policy Act toallow utility ownership of QFs and strengthening the thermal energyrequirements for entities seeking to be QFs;

·         Proposingrules that would allow a utility to seek to eliminate its mandatory QFpower purchase obligation for utilities in organized wholesale energy markets;and

·         Adopting rules to establish incentives for investment in newelectric transmission infrastructure.

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

***Electric Transmission Rate Regulation***—The FERC also regulates the rates charged and terms and conditions for electrictransmission services.  FERC policyencourages utilities to turn over the functional control over their electrictransmission assets and the related responsibility for the sale of electrictransmission services to an RTO. Each RTO separately files regionaltransmission tariff rates for approval by the FERC. All members within that RTOare then subjected to those rates. . PSCo is currently participating with other utilities in the developmentof WestConnect, which would provide certain regionalized transmission andwholesale energy market functions but would not be an RTO.

**RatemakingPrinciples**

***Summary ofRegulatory Agencies and Areas of Jurisdiction***— PSCo isregulated by the CPUC with respect to its facilities, rates, accounts, servicesand issuance of securities.  PSCo isregulated by the FERC with respect to its wholesale electric operations,accounting practices, wholesale sales for resale and the transmission ofelectricity in interstate commerce.

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

·       *ECA*— The ECA, effective Jan. 1, 2004, isan incentive adjustment mechanism that compares actual fuel and purchasedenergy expense in a calendar year to a benchmark formula. The ECA also providedfor an $11.25 million cap on any cost sharing over or under an allowed ECAformula rate. The current ECA mechanism expired Dec. 31, 2006.  Effective Jan. 1, 2007, the ECA has beenmodified to include an incentive adjustment to encourage efficient operation ofbase load coal plants and encourage cost reductions through purchases ofeconomical short-term energy.  The totalincentive payment to PSCo in any calendar year will not exceed $11.25million.  The ECA mechanism will berevised quarterly and interest will accrue monthly on the average deferredbalance.  The ECA will expire at theearlier of rates taking effect after Comanche 3 is placed in service, or Dec.31, 2010.

·       *PCCA*— The PCCA, which became effectiveJune 1, 2004, allows for recovery of purchased capacity payments tocertain power suppliers under specifically identified power purchase agreementsthat are not included in the determination of PSCo’s base electric rates orother recovery mechanisms.  EffectiveJan. 1, 2007, all prudently incurred purchased capacity costs will be recoveredthrough the PCCA.  The PCCA will expireat the earlier of rates taking effect after Comanche 3 is placed in service, orDec. 31, 2010.

·       *SCA*— The SCA allows PSCo to recover thedifference between its actual cost of fuel and the amount of these costsrecovered under its base steam service rates. The SCA rate is revised annuallyon Jan. 1, as well as on an interim basis to coincide with changes in fuelcosts.

·       *AQIR*— The AQIR recovers, over a 15-yearperiod, the incremental cost (including fuel and purchased energy) incurred byPSCo as a result of a voluntary plan, effective Jan. 1, 2003, to reduceemissions and improve air quality in the Denver metro area.

·       *DSMCA*— The DSMCA clause permits PSCo torecover DSM costs beginning Jan. 1, 2006 over eight years while non-laborincremental expenses and carrying costs associated with deferred DSM costs arerecovered on an annual basis. DSM costs incurred prior to Jan. 1, 2006 arerecovered over 5 years.  PSCo also has alow-income energy assistance program. The costs of this energy conservation andweatherization program for low-income customers are recovered through theDSMCA.

·       *Renewable Energy Service Adjustment (RESA)*— The RESA recovers costs associated with complying with the provisions of acitizen referred ballot initiative passed in 2004 that establishes a renewableportfolio standard for PSCo’s electric customers.  Currently, the RESA recovers the incrementalcosts of compliance with the renewable energy standard and is set at a level of0.6 percent of the net costs.

·       *Wind Energy Service Adjustment (WESA*) -The WESA provides for the recovery of certain costs associated with the provisionof wind energy resources from those customers subscribed as WindSourcerenewable energy customers.

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PSCo recovers fuel and purchased energy costs from itswholesale electric customers through a fuel cost adjustment clause accepted forfiling by the FERC.

***Performance-Based Regulation and Quality of ServiceRequirements***— PSCo currently operates under an electricand natural gas PBRP.  The majorcomponents of this regulatory plan include:

·       an electric QSP thatprovides for bill credits to customers if PSCo does not achieve certainperformance targets relating to electric reliability and customer servicethrough 2010; and

·       anatural gas QSP that provides for bill credits to customers if PSCo does notachieve certain performance targets relating to natural gas leak repair timeand customer service through 2010.

PSCo regularlymonitors and records as necessary an estimated customer refund obligation underthe PBRP. In April of each year following the measurement period, PSCofiles its proposed rate adjustment under the PBRP. The CPUC conductsproceedings to review and approve these rate adjustments annually.

For a furtherdiscussion of rate and regulatory matters see Note 11 to the ConsolidatedFinancial Statements.

**Capacityand Demand**

The uninterruptedsystem peak demand for PSCo’s electric utility for each of the last three yearsand the forecast for 2007, assuming normal weather, are listed below.
| ** ** | ** ** | **System Peak Demand (in MW)** | ** ** |
|------------|------------|----------------------------------------------------|------------|
| ** ** | ** ** | **2004**                                           | ** ** | **2005** | ** ** | **2006** | ** ** | **2007 Forecast** | ** ** |
| PSCo       |       | 6,483                                              |       | 6,975 |   | 6,757 |   | 6,751 |   |

 

The peak demandfor PSCo’s system typically occurs in the summer. The 2006 uninterrupted systempeak demand for PSCo occurred on July 19, 2006.

**Energy Sources and Related Transmission Initiatives**

PSCo expects tomeet its system capacity requirements through existing electric generatingstations, purchases from other utilities, independent power producers and powermarketers, new generation facilities, demand-side management options and phasedexpansion of existing generation at select power plants.

***Purchased Power***— PSCo has contractualarrangements to purchase power from other utilities and nonregulated energysuppliers.  Capacity is the measure ofthe rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricityproduced from a particular generating source over a period of time.  Long-term purchase power contracts typicallyrequire a periodic payment to secure the capacity from a particular generatingsource and a charge for the associated energy actually purchased from suchgenerating source.

PSCo also makesshort-term purchases to replace generation from company-owned units that areunavailable due to maintenance and unplanned outages, to comply with minimumavailability requirements, to obtain energy at a lower cost than that whichcould be produced by other resource options, including company-owned generationand/or long-term purchase power contracts, and for various other operatingrequirements.

***PSCo Resource Plan***— PSCo estimates itwill purchase approximately 39 percent of its total electric system energyneeds for 2007 and generate the remainder with PSCo-ownedresources.  Additional capacity has been secured under contractmaking additional energy available for purchase, if required. PSCo currently hasunder contract or through owned generation, the resources necessary to meet itsanticipated 2007 load obligation.

In 2004, PSCo filed aleast-cost resource plan (LCP) with the CPUC. PSCo’s proposed to meet future resource needs through a combination of utilitybuilt generation, DSM, and power purchases. The CPUC approved PSCo’s plan to construct a 750 MW pulverizedcoal-fired unit at the existing Comanche power station located near Pueblo,Colo. and install additional emission control equipment on the two existingComanche station units.  The CPUC alsocalled for PSCo to acquire the remaining resource needs through an all-sourcecompetitive bidding process.

PSCo began constructionof the facility in the fall of 2005, which is planned for completion in thefall of 2009.  Based on CPUC approval,construction costs are limited for the Comanche 3 project (i.e., the new unitand the emission controls on existing units 1 and 2). The CPUC also approved aregulatory plan that authorizes PSCo to increase the equity component of itscapital structure up to 60 percent to offset the debt equivalent value of PSCo’sexisting power purchase contracts and to otherwise improve

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PSCo’s financialstrength.  Depending upon PSCo’s seniorunsecured debt rating during the time of PSCo general rate cases, the approvedsettlement permits PSCo to include various amounts of construction work inprogress that are associated with the Comanche 3 project in rate base withoutan offset for allowance for funds used during construction.

PSCo has signedagreements with Intermountain Rural Electric Association (IREA) that define therespective rights and obligations of PSCo and IREA in the transfer of capacityownership in the Comanche 3 unit.  PSCo andHoly Cross have agreed to terms for Holy Cross ownership of a share of Comanche3 and Holy Cross has been making its agreed-upon contributions towardconstruction of the plant.

For the remainingresource needs, PSCo selected bids for approximately 30 MW of DSM resources,approximately 1,300 MW of gas-fired generation resources and approximately 775MW of wind generation resources.  Thesebids, together with Comanche 3, and the additional DSM agreed to in the LCPsettlement agreement, are expected to meet PSCo’s resource needs through 2012.

***Renewable Energy Portfolio Standards —***In November 2004, an amendment to the Colorado statutes was passed byreferendum requiring implementation of a renewable energy portfolio standard(RES) for electric service.  The lawrequires PSCo to generate, or cause to be generated, a certain level ofelectricity from eligible renewable resources. During 2006, the CPUC determined that compliance with the RES should bemeasured through the acquisition of renewable energy credits either with orwithout the accompanying renewable energy; that the utility purchaser owns therenewable energy credits associated with existing contracts where the powerpurchase agreement is silent on the issue; that Colorado utilities should berequired to file implementation plans; and the methods utilities should use fordetermining the budget available for renewable resources.  In April 2006, the CPUC issued rules thatestablish the process utilities are to follow in implementing the RES.  PSCo filed its first annual compliance planunder these rules on Aug. 31, 2006.  Theplan demonstrates that PSCo is expected to meet the RES beginning in 2007 asrequired.

On Aug. 31, 2006,PSCo filed with the CPUC an application for approval of its 2007 complianceplan for the RES rules.  As a part of itsplan, PSCo requested approval to continue its existing 0.60 percent RESadjustment rider.  Through its existingresources and contracts entered into in 2006, PSCo anticipates havingsufficient non-solar renewable energy resources to meet the standard through atleast 2016.  In June 2006, PSCo issued arequest for proposal to provide solar renewable energy credits and expects toenter into contracts to meet its obligation for customer-sited solar resources.  On Sept. 1, 2006, PSCo executed a twenty-yearsolar power purchase agreement, which are expected to provide about 16,000 MWhours per year and accompanying solar renewable energy credits beginning in2008.

***RESA —***On Dec. 1, 2005, PSCo filedwith the CPUC to implement a new 1-percent rider that would apply to eachcustomer’s total electric bill generating approximately $22 million in annualrevenue.  The revenues collected underthe RESA will be used to acquire sufficient solar resources to meet the on-sitesolar system requirements in the Colorado statutes.  On Feb. 14, 2006, PSCo and the other partiesto the case filed a stipulation agreeing to reduce the RESA rider to 0.60percent and to provide monthly reports. The RESA rider was approved by the CPUC effective March 1, 2006.

***Purchased Transmission Services***— PSCohas contractual arrangements with regional transmission service providers todeliver power and energy to PSCo’s native load customers, which are retail andwholesale load obligations with terms of more than one year.

**Fuel Supply and Costs**

The followingtable shows the delivered cost per MMBtu of each significant category of fuelconsumed for electric generation, the percentage of total fuel requirementsrepresented by each category of fuel and the total weighted average cost of allfuels.
| ** ** | ** ** | **Coal**   | ** ** | **Natural Gas ** | ** ** | **Average Fuel** | ** ** |
|------------|------------|------------|------------|----------------------------|------------|-----------------------|------------|
| ** ** | ** ** | **Cost**   | ** ** | **Percent**                | ** ** | **Cost**              | ** ** | **Percent** | ** ** | **Cost** | ** ** |
| ** ** | ** ** | ** ** | ** ** | ** **                 | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| 2006       |       | $          | 1.24       |                       | 85         | %                     | $          | 6.52 |   | 15 | % | $ | 2.01 |   |
| 2005       |       | $          | 1.01       |                       | 85         | %                     | $          | 7.56 |   | 15 | % | $ | 2.00 |   |
| 2004       |       | $          | 0.89       |                       | 87         | %                     | $          | 5.61 |   | 13 | % | $ | 1.52 |   |

 

See additionaldiscussion of fuel supply and costs under Risks Associated with Our Businessunder Item 1A.

***Fuel Sources***—******Coal inventorylevels may vary widely among plants. However, PSCo normally maintains approximately 30 days of coal inventoryat each plant site.  Coal supplyinventories at Dec. 31, 2006, were approximately 30 days usage, based onthe maximum burn rate for all of PSCo’s coal-fired plants.  PSCo’s generation stations use low-sulfurwestern coal purchased primarily under long-term contracts with suppliersoperating in Colorado and Wyoming. During 2006, PSCo’s

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coal requirementsfor existing plants were approximately 10 million tons.

PSCo hascontracted for coal suppliers to supply approximately 98 percent of its coalrequirements in 2007, 70 percent of its coal requirements in 2008 and 60percent of its coal requirements in 2009. Any remaining requirements will be purchased on the spot market.

PSCo has coaltransportation contracts that provide for delivery of approximately 100 percentof 2007 coal requirements, 100 percent of 2008 coal requirements and 40 percentof 2009 coal requirements.  Coal deliverymay be subject to short-term interruptions or reductions due to transportationproblems, weather, and availability of equipment.

PSCo uses bothfirm and interruptible natural gas and standby oil in combustion turbines andcertain boilers.  Natural gas suppliesfor PSCo’s power plants are procured under short- and intermediate- termcontracts.  This natural gas istransported to the plants on various interstate pipeline systems with contractsthat expire in various years from 2007 through 2025.  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, 2006, PSCo’s commitments relatedto these contracts were approximately $328 million.

**Commodity Marketing Operations**

PSCo conductsvarious wholesale marketing operations, including the purchase and sale ofelectric capacity, energy and energy related products.  PSCo uses physical and financial instrumentsto minimize commodity price and credit risk and hedge supplies andpurchases.  See additional discussionunder Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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**PSCo ElectricOperating Statistics**

 
| ** **                                    | ** ** | **Year Ended Dec. 31,** | ** ** |
|-----------------------------------------------|------------|----------------------------------------|------------|
| ** **                                    | ** ** | **2006**                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Electric  Sales (Millions of Kwh)**         | ** ** | ** **                             | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential                                   |       | 8,557                                  |       | 8,390 |   | 8,066 |   |
| Commercial and Industrial                     |       | 18,398                                 |       | 17,857 |   | 17,409 |   |
| Public Authorities and Other                  |       | 243                                    |       | 234 |   | 252 |   |
| Total Retail                                  |       | 27,198                                 |       | 26,481 |   | 25,727 |   |
| Sales for Resale                              |       | 7,820                                  |       | 8,112 |   | 8,372 |   |
| Total Energy Sold                             |       | 35,018                                 |       | 34,593 |   | 34,099 |   |
|                                          |       |                                   |       |   |   |   |   |
| **Number  of Customers at End of Period**     |       |                                   |       |   |   |   |   |
| Residential                                   |       | 1,113,293                              |       | 1,091,072 |   | 1,083,872 |   |
| Commercial and Industrial                     |       | 147,349                                |       | 145,520 |   | 144,111 |   |
| Public Authorities and Other                  |       | 60,381                                 |       | 62,985 |   | 66,797 |   |
| Total Retail                                  |       | 1,321,023                              |       | 1,299,577 |   | 1,294,780 |   |
| Wholesale                                     |       | 49                                     |       | 62 |   | 69 |   |
| Total Customers                               |       | 1,321,072                              |       | 1,299,639 |   | 1,294,849 |   |
|                                          |       |                                   |       |   |   |   |   |
| **Electric  Revenues (Thousands of Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                   |       | $                                      | 756,701    |   | $ | 760,919 |   | $ | 672,496 |   |
| Commercial and Industrial                     |       | 1,251,390                              |       | 1,240,697 |   | 1,080,660 |   |
| Public Authorities and Other                  |       | 38,775                                 |       | 38,977 |   | 36,257 |   |
| Total Retail                                  |       | 2,046,866                              |       | 2,040,593 |   | 1,789,413 |   |
| Wholesale                                     |       | 408,859                                |       | 416,503 |   | 403,155 |   |
| Other Electric Revenues                       |       | 49,720                                 |       | 46,932 |   | 2,060 |   |
| Total Electric Revenues                       |       | $                                      | 2,505,445  |   | $ | 2,504,028 |   | $ | 2,194,628 |   |
|                                          |       |                                   |       |   |   |   |   |
| Kwh Sales per  Retail Customer                |       | 20,589                                 |       | 20,377 |   | 19,870 |   |
| Revenue per  Retail Customer                  |       | $                                      | 1,549.46   |   | $ | 1,570.20 |   | $ | 1,382.02 |   |
| Residential  Revenue per Kwh                  |       | 8.84                                   | ¢     | 9.07 | ¢ | 8.34 | ¢ |
| Commercial and  Industrial Revenue per Kwh    |       | 6.80                                   | ¢     | 6.95 | ¢ | 6.21 | ¢ |
| Wholesale Revenue per  Kwh                    |       | 5.23                                   | ¢     | 5.13 | ¢ | 4.82 | ¢ |

 

**NATURAL GAS UTILITY OPERATIONS**

**Summaryof Recent Regulatory Developments**

The most significantrecent developments in the natural gas operations of PSCo have been thecontinued volatility in wholesale natural gas market prices and the continuedtrend toward declining use per customer by residential customers as a result ofimproved building construction technologies and higher applianceefficiencies.  From 1996 to 2006, averageannual sales to the typical PSCo residential customer declined from 99 MMBtuper year to 80 MMBtu per year on a weather-normalized basis.  Although recent wholesale price increases donot directly affect earnings because of natural gas cost recovery mechanisms,the high prices are expected to encourage further efficiency efforts bycustomers.

# **Ratemaking Principles**

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

***Purchased Gas and Conservation Cost Recovery Mechanisms***—****PSCo has two retailadjustment clauses that recover purchased gas and other resource costs:

·     *GCA***— The GCA mechanism allows PSCo to recover its actual costs ofpurchased gas, including costs for upstream pipeline services PSCo incurs tomeet the requirements of its local distribution system customers.  The GCA is revised monthly to allow forchanges in gas rates.

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·     *DSMCA***— PSCo has a low-income energy assistance program. Thecosts of this energy conservation and weatherization program for low-incomecustomers are recovered through the gas DSMCA.

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

For a further discussionof rate and regulatory matters see Note 11 to the Consolidated FinancialStatements.

# **Capabilityand Demand**

PSCo projects peakday natural gas supply requirements for firm sales and backup transportation,which include transportation customers contracting for firm supply backup, tobe 1,816,362 MMBtu.  In addition, firmtransportation customers hold 534,761 MMBtu for PSCo of capacity without supplybackup.  Total firm delivery obligationfor PSCo is 2,351,123 MMBtu per day.  Themaximum daily deliveries for PSCo in 2006 for firm and interruptible serviceswere 1,872,640 MMBtu on Feb. 17, 2006.

PSCo purchasesnatural gas from independent suppliers. These purchases are generally priced based on market indices thatreflect current prices.  The natural gasis delivered under natural gas transportation agreements with interstatepipelines.  These agreements provide forfirm deliverable pipeline capacity of approximately 1,618,864 MMBtu/day, whichincludes 831,866 MMBtu of supplies held under third-party underground storageagreements.  In addition, PSCo operatesthree company-owned underground storage facilities, which provide about 40,000MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day salesobligations are primarily purchased at PSCo’s city gate meter stations and asmall amount is received directly from wellhead sources.

PSCo has closedthe Leyden Storage Field and is in the monitoring phase of the abandonmentprocess, which is expected to continue until December 2007.  See further discussion in Item 1,Environmental Matters.

PSCo is requiredby CPUC regulations to file a natural gas purchase plan by June of each yearprojecting and describing the quantities of natural gas supplies, upstreamservices and the costs of those supplies and services for the period beginningJuly 1 through June 30 of the following year. PSCo is also required to file a natural gas purchase report by Octoberof each year reporting actual quantities and costs incurred for natural gassupplies and upstream services for the 12-month period ending the previous June30.

**Natural Gas Supply and Costs**

PSCo activelyseeks natural gas supply, transportation and storage alternatives to yield adiversified portfolio that provides increased flexibility, decreasedinterruption and financial risk, and economical rates.  In addition, PSCo conducts natural gas pricehedging activities that have been approved by the CPUC.  This diversification involves numerous supplysources with varied contract lengths.

The followingtable summarizes the average delivered cost per MMBtu of natural gas purchasedfor resale by PSCo’s regulated retail natural gas distribution business:

| 2006 |   | $ | 7.09 |   |
|------|--------|---|------|--------|
| 2005 |   | $ | 8.01 |   |
| 2004 |   | $ | 6.30 |   |

 

PSCo has certainnatural gas supply, transportation and storage agreements that includeobligations for the purchase and/or delivery of specified volumes of naturalgas or to make payments in lieu of delivery. At Dec. 31, 2006, PSCo was committed to approximately $1.2 billion insuch obligations under these contracts, which expire in various years from 2007through 2025.

PSCo purchasesnatural gas by optimizing a balance of long-term and short-term natural gaspurchases, firm transportation and natural gas storage contracts.  During 2006, PSCo purchased natural gas fromapproximately 37 suppliers.

See additionaldiscussion of natural gas costs under Factors Affecting Results of ContinuingOperations in Management’s Discussion and Analysis under Item 7.

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**PSCo Natural GasOperating Statistics**
| ** **                                       | ** ** | **Year Ended Dec. 31,** | ** ** |
|--------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                       | ** ** | **2006**                               | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Natural  Gas Deliveries (Thousands of MMBtu)** |       |                                   |       |   |   |   |   |
| Residential                                      |       | 87,200                                 |       | 91,086 |   | 88,726 |   |
| Commercial and Industrial                        |       | 37,923                                 |       | 38,475 |   | 38,501 |   |
| Total Retail                                     |       | 125,123                                |       | 129,561 |   | 127,227 |   |
| Transportation and Other                         |       | 121,501                                |       | 118,214 |   | 102,139 |   |
| Total Deliveries                                 |       | 246,624                                |       | 247,775 |   | 229,366 |   |
|                                             |       |                                   |       |   |   |   |   |
| **Number  of customers at end of period**        |       |                                   |       |   |   |   |   |
| Residential                                      |       | 1,154,598                              |       | 1,130,888 |   | 1,111,377 |   |
| Commercial and Industrial                        |       | 96,787                                 |       | 95,302 |   | 94,414 |   |
| Total Retail                                     |       | 1,251,385                              |       | 1,226,190 |   | 1,205,791 |   |
| Transportation and Other                         |       | 3,945                                  |       | 3,728 |   | 3,506 |   |
| Total Customers                                  |       | 1,255,330                              |       | 1,229,918 |   | 1,209,297 |   |
|                                             |       |                                   |       |   |   |   |   |
| **Natural  Gas Revenues (Thousands of Dollars)** |       |                                   |       |   |   |   |   |
| Residential                                      |       | $                                      | 866,176    |   | $ | 924,030 |   | $ | 742,724 |   |
| Commercial and Industrial                        |       | 342,404                                |       | 356,374 |   | 288,002 |   |
| Total Retail                                     |       | 1,208,580                              |       | 1,280,404 |   | 1,030,726 |   |
| Transportation and Other                         |       | 53,715                                 |       | 48,630 |   | 43,263 |   |
| Total Natural Gas Revenues                       |       | $                                      | 1,262,295  |   | $ | 1,329,034 |   | $ | 1,073,989 |   |
|                                             |       |                                   |       |   |   |   |   |
| MMBtu Sales per  Retail Customer                 |       | 99.99                                  |       | 105.66 |   | 105.51 |   |
| Revenue per  Retail Customer                     |       | $                                      | 965.79     |   | $ | 1,044.21 |   | $ | 854.81 |   |
| Residential  Revenue per MMBtu                   |       | $                                      | 9.93       |   | $ | 10.14 |   | $ | 8.37 |   |
| Commercial and  Industrial Revenue per MMBtu     |       | $                                      | 9.03       |   | $ | 9.26 |   | $ | 7.48 |   |
| Transportation and  Other Revenue per MMBtu      |       | $                                      | 0.44       |   | $ | 0.41 |   | $ | 0.42 |   |

#  

# **ENVIRONMENTALMATTERS**

Certain of PSCo’sfacilities are regulated by federal and state environmental agencies. Theseagencies have jurisdiction over air emissions, water quality, wastewaterdischarges, solid wastes and hazardous substances. Various company activitiesrequire registrations, permits, licenses, inspections and approvals from theseagencies. PSCo has received all necessary authorizations for the constructionand continued operation of its generation, transmission and distributionsystems. Company facilities have been designed and constructed to operate incompliance with applicable environmental standards.

PSCo strives to complywith all environmental regulations applicable to its operations. However, it isnot possible to determine when or to what extent additional facilities ormodifications of existing or planned facilities will be required as a result ofchanges to environmental regulations, interpretations or enforcement policiesor, what effect future laws or regulations may have upon PSCo’s operations. Formore information on environmental contingencies, see Note 12 to theConsolidated Financial Statements and the matter discussed below.

***Leyden Gas Storage Facility***— InFebruary 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gasstorage 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. In November 2006, PSCo filed a natural gas rate case with the CPUCrequesting recovery of additional Leyden costs, plus unrecovered amounts previouslyauthorized from the last rate case, which amounted to $5.9 million to beamortized over four years.  The totalamount PSCo is requesting be recovered from customers is $7.7 million.

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# **EMPLOYEES**

The number of full-timePSCo employees on Dec. 31, 2006 was 2,589. Of these full-time employees, 2,146,or 83 percent, are covered under collective bargaining agreements. See Note 7to the Consolidated Financial Statements for further discussion. Employees ofXcel Energy Services Inc., a subsidiary of Xcel Energy, also provide servicesto PSCo.

**Item 1A — Risk Factors**

**RisksAssociated with Our Business**

***Our profitability depends in part on our ability to recover costs fromour customers and there may be changes in circumstances or in the regulatoryenvironment that impair our ability to recover costs from our customers.***

We aresubject to comprehensive regulation by several federal and state utilityregulatory agencies. The state utility commissions regulate many aspects of ourutility operations, including siting and construction of facilities, customerservice and the rates that we can charge customers.  The FERC has jurisdiction, among otherthings, over wholesale rates for electric transmission service and the sale ofelectric energy in interstate commerce.

Ourprofitability is dependent on our ability to recover costs related to providingenergy and utility services to our customers. We currently provide service at rates approved by one or more regulatorycommissions.  These rates are generallyregulated based on an analysis of our expenses incurred in a test year.  Thus, the rates we are allowed to charge mayor may not match our expenses at any given time.  While rate regulation is premised on providinga reasonable opportunity to earn a reasonable rate of return on investedcapital, there can be no assurance that the applicable regulatory commissionwill judge all of our costs to have been prudently incurred or that theregulatory process in which rates are determined will always result in ratesthat will produce full recovery of our costs.  Rising fuel costs could increase the risk that we will not be able tofully recover our under-recovered fuel costs from our customers.  Furthermore, there could be changes in theregulatory environment that would impair our ability to recover costshistorically collected from our customers. If all of our costs are not recovered through customer rates, we couldincur financial operating losses, which, over the long term, could jeopardizeour ability to meet our financial obligations.

We areunable to predict the impact on our operating results from the futureregulatory activities of any of these agencies. Changes in regulations or theimposition 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, including paying debt payments.

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

Wecannot be assured that any of our current ratings will remain in effect for anygiven period of time or that a rating will not be lowered or withdrawn entirelyby a rating agency if, in its judgment, circumstances in the future sowarrant.  In addition, our credit ratingsmay change as a result of the differing methodologies or change in themethodologies used by the various rating agencies.  For example, Standard and Poor’s calculatesan imputed debt associated with capacity payments from purchased powercontracts.   An increase in the overalllevel of capacity payments would increase the amount of imputed debt, based onStandard and Poor’s methodology. Therefore, our credit ratings could be adversely affected based on thelevel of capacity payments associated with purchased power contracts or changesin how imputed debt is determined.  Anydowngrade could lead to higher borrowing costs.

***We are subject to commodity risks and other risks associated withenergy markets.***

Weengage in wholesale sales and purchases of electric capacity, energy andenergy-related products and are subject to market supply and commodity pricerisk.  Commodity price changes can affectthe value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a dailybasis (mark-to-market accounting), which may cause earnings variability. Weutilize quoted market prices to the maximum extent possible in determining thevalue of these derivative commodity instruments.  For positions for which market prices are notavailable, we utilize models based on forward price curves. These modelsincorporate estimates and assumptions as to a variety of factors such aspricing relationships between various energy commodities and geographiclocations. Actual experience can vary significantly from these estimates andassumptions and significant changes from our assumptions could causesignificant earnings variability.

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If weencounter market supply shortages, we may be unable to fulfill contractualobligations to our retail, wholesale and other customers at previouslyauthorized or anticipated costs.  Anysuch supply shortages could cause us to seek alternative supply services atpotentially higher costs or suffer increased liability for unfulfilledcontractual obligations.  Anysignificantly higher energy or fuel costs relative to corresponding salescommitments would have a negative impact on our cash flows and couldpotentially result in economic losses.

***We are subject to interest rate risk.***

Ifinterest rates increase, we may incur increased interest expense on variableinterest debt or short-term borrowings, which could have an adverse impact onour operating results.

***We are subject to credit risks.***

Creditrisk includes the risk that counterparties that owe us money or product willbreach their obligations. Should the counterparties to these arrangements failto perform, we may be forced to enter into alternative arrangements. In thatevent, our financial results could be adversely affected and we could incurlosses.

***We have received a notice from the IRS proposing to disallow certaininterest expense deductions that we claimed in 1993 through 1999. Should theIRS ultimately prevail on this issue, our liquidity position and financialresults could be materially adversely affected.***

Ourwholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanentlife insurance policies on some of our employees, known as COLI. At various times,borrowings have been made against the cash values of these COLI policies anddeductions taken on the interest expense on these borrowings. The IRS haschallenged the deductibility of such interest expense deductions and hasdisallowed the deductions taken in tax years 1993 through 1999.

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

AfterXcel Energy filed this suit, the IRS sent two statutory notices of deficiencyof tax, penalty and interest for 1995 through 1999. Xcel Energy has filed U.S.Tax Court petitions challenging those notices. Xcel Energy anticipates thedispute relating to its interest expense deductions will be resolved in therefund suit that is pending in the Minnesota Federal District Court and the TaxCourt petitions will be held in abeyance pending the outcome of the refundlitigation. In the third quarter of 2006, Xcel Energy also received a statutorynotice of deficiency from the IRS for tax years 2000 through 2002 and timelyfiled a Tax Court petition challenging the denial of the COLI interest expensedeductions for those years.

OnOct. 12, 2005, the district court denied Xcel Energy’s motion for summaryjudgment on the grounds that there were disputed issues of material fact thatrequired a trial for resolution. At the same time, the district court deniedthe government’s motion for summary judgment that was based on its contentionthat PSCo had lacked an insurable interest in the lives of the employeesinsured under the COLI policies. However, the district court granted XcelEnergy’s motion for partial summary judgment on the grounds that PSCo did havethe requisite insurable interest.

On May5, 2006, Xcel Energy filed a second motion for summary judgment. On Aug. 18,2006, the U.S. government filed a second motion for summary judgment.  On February 14, 2007 the Magistrate Judgeissued his Report and Recommendation (R&R) to the Judge concerning bothmotions. In his R&R the Magistrate Judge recommends both motions be denieddue to fact issues in dispute. Both parties will have an opportunity to file objectionsby March 5, 2007 to the Magistrate Judge’s recommendations. The Judge will thenhave broad authority to, among other things, accept or reject therecommendations in whole or in part.  Ifboth sides’ motions are ultimately denied, a trial is set to begin on July 24,2007.

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XcelEnergy believes that the tax deduction for interest expense on the COLI policyloans is in full compliance with the tax law. Accordingly, PSRI has notrecorded any provision for income tax or related interest or penalties, and hascontinued to take deductions for interest expense on policy loans on its incometax returns for subsequent years. The litigation could require several years toreach final resolution. Defense of Xcel Energy’s position may requiresignificant cash outlays, which may or may not be recoverable in a courtproceeding. The ultimate resolution of this matter is uncertain and could havea material adverse effect on our financial position, results of operations andcash flows.

Shouldthe IRS ultimately prevail on this issue, tax and interest payable through Dec.31, 2006, would reduce earnings by an estimated $421 million. Xcel Energy hasreceived formal notification that the IRS will seek penalties. If penalties(plus associated interest) also are included, the total exposure through Dec.31, 2006, is approximately $499 million. In addition, Our annual earnings for2007 would be reduced by approximately $49 million, after tax, if COLI interestexpense deductions were no longer available.

***We are subject to environmental laws and regulations, compliance withwhich could be difficult and costly.***

We aresubject to a number of environmental laws and regulations that affect manyaspects of our past, present and future operations, including air emissions,water quality, wastewater discharges and the management of wastes and hazardoussubstances.  These laws and regulationsgenerally require us to obtain and comply with a wide variety of environmentalregistrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can alsorequire us to restrict or limit the output of certain facilities or the use ofcertain fuels, to install pollution control equipment at our facilities, cleanup spills and correct environmental hazards and other contamination.  Both public officials and private individualsmay seek to enforce the applicable environmental laws and regulations againstus.  We must pay all or a portion of thecost to remediate (i.e. clean-up) sites where our past activities, or theactivities of certain other parties, caused environmental contamination.  At Dec. 31, 2006, these sites included:

·                  the sites offormer manufactured gas plants operated by our subsidiaries or predecessors;and

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

Inaddition, existing environmental laws or regulations may be revised, new lawsor regulations seeking to protect the environment may be adopted or becomeapplicable to us and we may incur additional unanticipated obligations orliabilities under existing environmental 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.

Forfurther discussion see Note 12 to the Consolidated Financial Statements.

***Economic conditions could negatively impact our business.***

Ouroperations are affected by local and national economic conditions.  The consequences of a prolonged recession mayinclude a lower level of economic activity and uncertainty regarding energyprices and the capital and commodity markets. A lower level of economic activity might result in a decline in energyconsumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as aresult of recession or otherwise, also may affect the cost of capital and ourability to raise capital.

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***Our operations could be impacted by war, acts of terrorism or threatsof terrorism.***

Theconflict in Iraq and any other military strikes or sustained military campaignmay affect our operations in unpredictable ways and may cause disruptions offuel supplies and markets, particularly with respect to natural gas andpurchased energy.  War and thepossibility of further war may have an adverse impact on the economy in general.

Ourgeneration plants, fuel storage facilities, transmission and distributionfacilities and information systems may be targets of terrorist activities thatcould disrupt 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 forterrorism has subjected our operations to increased risks and could have amaterial adverse effect on our business. While we have already incurred increased costs for security and capitalexpenditures in response to these risks, we may experience additional capitaland operating costs to implement security for our plants, such as additionalphysical plant security and additional security personnel. 

Theinsurance industry has also been affected by these events and the availabilityof insurance covering risks we and our competitors typically insure against maydecrease.  In addition, the insurance weare able to obtain may have higher deductibles, higher premiums and more restrictivepolicy terms.

***A disruption or black-out of the regional electric transmission gridcould negatively impact our business.***

Becauseour generation and transmission systems are part of an interconnected regionalgrid, we face the risk of possible loss of business due to a disruption orblack-out caused by an event (severe storm, generator or transmission facilityoutage) on a neighboring system or the actions of a neighboring utility,similar to the Aug. 14, 2003 black-out in portions of the eastern U.S. andCanada.  Any such disruption could resultin a significant decrease in revenues and significant additional costs torepair assets, which could have a material adverse impact on our financialcondition and results of operations.

***Reduced coal availability could negatively impact our business.***

Ourcoal generation portfolio is heavily dependent on coal supplies located in thePowder River Basin of Wyoming. Approximately 50 percent of PSCo annual coal requirement comes from thisarea. Coal generation comprises approximately 85 percent our annualgeneration.  We have recently experienceddisruptions in the delivery of Powder River Basin coal to our facilities andsuch disruptions could occur again in the future.  Coal delivery may be subject to short-terminterruptions or reductions due to various factors, including transportationproblems, weather and availability of equipment.  Failure or delay by our suppliers of coaldeliveries could disrupt our ability to deliver electricity and require us toincur additional expenses to meet the needs of our customers.  In addition, as agreements expire with oursuppliers, we may not be able to enter into new agreements for coal delivery onequivalent terms.

***Rising energy prices could negatively impact our business.***

Higherfuel costs could significantly impact our 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 our results ofoperations.  Delays in the timing of thecollection of fuel cost recoveries as compared with expenditures for fuelpurchases could have an impact on our cash flows.  We are unable to predict the future prices orthe ultimate impact of such prices on our results of operations or cash flows.

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

Ourelectric utility and natural gas businesses are seasonal and weather patternscan have a material impact on our operating performance. Demand for electricityis often greater in the summer and winter months associated with cooling andheating.  Because natural gas is heavilyused for residential and commercial heating, the demand for this productdepends heavily upon weather patterns throughout our service territory, and asignificant amount of natural gas revenues are recognized in the first and fourthquarters related to the heating season.  Accordingly,our operations have historically generated less revenues and income whenweather conditions are milder in the winter and cooler in the summer. Unusuallymild winters and summers could have an adverse effect on our financialcondition and results of operations.

***Our natural gas distributionactivities involve numerous risks that may result in accidents and otheroperating risks and costs.***

 

Thereare inherent in our natural gas distribution activities a variety of hazardsand operating risks, such as leaks, explosions and mechanical problems, thatcould cause substantial financial losses. In addition, these risks could result in loss of human life, significantdamage to property, environmental pollution, impairment of our operations andsubstantial losses to us.  In accordancewith customary industry practice, we maintain insurance against some, but notall, of these risks and losses.  Theoccurrence of any of these events not fully covered by insurance could have amaterial adverse effect 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.

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***Increased risks of regulatory penalties could negatively impact our business***

TheEnergy Act increased FERC’s civil penalty authority for violation of FERCstatutes, rules and orders.  FERC can nowimpose penalties of $1 million per violation per day.  Effective June 1, 2007, approximately 80electric reliability standards that were historically subject to voluntarycompliance will become mandatory and subject to potential civil penalties forviolations.  If a serious reliabilityincident did occur, it could have a material adverse effect on our operationsor financial results.

***Increasing costs associated with our defined benefit retirement plansand other employee-related benefits may adversely affect our results ofoperations, financial position, or liquidity.***

Wehave defined benefit and postretirement plans that cover substantially all ofour employees.  Assumptions related tofuture costs, return on investments, interest rates and other actuarialassumptions have a significant impact on our funding requirements related tothese plans.  These estimates andassumptions may change based on actual stock market performance, changes ininterest rates and any changes in governmental regulations.  In addition, the Pension Protection Act of2006 changed the minimum funding requirements for defined benefit pension plansbeginning in 2008.  Therefore, ourfunding requirements may change and our contributions could be required in thefuture.

***Increasing costs associated with health care plans may adversely affectour results of operations, financial position or liquidity.***

Thecosts of providing health care benefits to our employees and retirees haveincreased substantially in recent years. We believe that our employee benefit costs, including costs related tohealth care plans for our employees and former employees, will continue to rise.  The increasing costs and funding requirementsassociated with our health care plans may adversely affect our results ofoperations, financial position, or liquidity. 

***As we are a subsidiary of Xcel Energy, 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 alternate sources of funds to meet our cash needs.***

Ifeither Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s creditrating below investment grade, Xcel Energy may be required to provide creditenhancements in the form of cash collateral, letters of credit or othersecurity to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’swere to downgrade Xcel Energy’s debt securities below investment grade, itwould increase Xcel Energy’s cost of capital and restrict its access to thecapital markets.  This could limit XcelEnergy’s ability to contribute equity or make loans to us, or may cause XcelEnergy to seek additional 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 we are a subsidiary of Xcel Energy, we may be negatively affected byevents at Xcel Energy and its affiliates. If Xcel Energy were to become obligated to make payments under various guaranteesand bond indemnities or to fund its other contingent liabilities, or if XcelEnergy’s credit ratings and access to capital were restricted, this could limitXcel Energy’s ability to contribute equity or make loans to us, or may causeXcel Energy to seek 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.***

As ofDec. 31, 2006, Xcel Energy had approximately $6.4 billion of long-term debt and$1.0 billion of short-term debt or current maturities.  Xcel Energy provides various guarantees andbond indemnities supporting some of its subsidiaries by guaranteeing thepayment or performance by these subsidiaries of specified agreements or transactions.  Xcel Energy also has other contingentliabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guaranteesis based upon the net

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liabilityof the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy’s guaranteeslimit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2006, Xcel Energy hadguarantees outstanding with a maximum stated amount of approximately $76.2million and $17.5 million of exposure. Xcel Energy has also provided indemnities to sureties in respect ofbonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of Dec.31, 2006, was approximately $118.6 million.  Xcel Energy’s total exposure under theseindemnities cannot be determined at this time. If Xcel Energy were to become obligated to make payments under theseguarantees and bond indemnities or become obligated to fund the othercontingent liabilities, it could limit Xcel Energy’s ability to contributeequity or make loans to us, or may cause Xcel Energy to seek additional oraccelerated 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.

***We are a wholly owned subsidiary of Xcel Energy.  Xcel Energy can exercise substantial controlover our dividend policy and business and operations and may exercise thatcontrol in a manner that may be perceived to be adverse to our interests.***

Ourboard of directors, as well as many of our executive officers, are officers ofXcel Energy.  Our board makesdeterminations with respect to a number of significant corporate events,including the payment of our dividends.

Wehave historically paid quarterly dividends to Xcel Energy.  In 2006, 2005 and 2004 we paid $195.6million, $62.6 million and $243.9 million of dividends to Xcel Energy,respectively.  If Xcel Energy’s cashrequirements increase, our board of directors could decide to increase thedividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect ourliquidity.  The amount of dividends thatwe can pay is also limited to some extent by our indenture for our firstmortgage bonds.

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

None.

**Item2**— **Properties**

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

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Electric utilitygenerating stations:
| ** **                                | ** ** | ** **       | ** ** | ** **    | ** ** | **Summer 2006 Net** | ** ** |
|-------------------------------------------|------------|------------------|------------|---------------|------------|-------------------------------|------------|
| ** **                                | ** ** | ** **       | ** ** | ** **    | ** ** | **Dependable**                | ** ** |
| **Station, City and Unit** | ** ** | **Fuel**         | ** ** | **Installed** | ** ** | **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                   |       | Coal             |       | 1979-1980     |       | 83                            | (a)        |
| Hayden-Hayden, CO 2 Units                 |       | Coal             |       | 1965-1976     |       | 237                           | (b)        |
| 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  Generators:                       |       |             |       |          |       |                          |       |
| Cherokee-Denver, CO 2 Units               |       |             |       | 1967          |       | 6                             |       |
|                                      |       |             |       | Total         |       | 3,836                         |       |

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

(b)            Basedon PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit2.

Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2006:

| Conductor Miles | ** ** |
|----------------------|------------|
| 345 KV               |       | 957 |   |
| 230 KV               |       | 10,787 |   |
| 138 KV               |       | 92 |   |
| 115 KV               |       | 4,851 |   |
| Less than 115 KV     |       | 71,174 |   |

 

PSCo had 209 electricutility transmission and distribution substations at Dec. 31, 2006.

Natural gas utility mainsat Dec. 31, 2006:

 

| Miles        | ** ** |
|--------------|------------|
| Transmission |       | 2,303 |   |
| Distribution |       | 20,599 |   |

 

**Item3**— **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.

For a 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 and Note 11 to the Consolidated FinancialStatements under Item 8, incorporated by reference.

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**Item4**— **Submission of Mattersto 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**

**Item5**— **Market for Registrant’sCommon Equity, Related Stockholder Matters and****Issuer Purchases of Equity Securities**

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

PSCo had dividend restrictions imposed by its debt agreements and FERCrules.  PSCo’s credit agreement prohibitsdividends or other similar distributions unless covenants relating to PSCo’scapitalization are met.  Dividends arealso subject to the FERC’s jurisdiction under the Federal Power Act, whichprohibits the payment of dividends out of capital accounts; payment ofdividends is allowed out of retained earnings only.

The dividends declared during 2006 and 2005 were as follows:

 

| Quarter Ended                   | ** ** |
|--------------------------------------|------------|
| **(Thousands of Dollars)** | ** ** |
| **March 31, 2006**         | ** ** | **June 30, 2006** | ** ** | **Sept. 30, 2006** | ** ** | **Dec. 31, 2006** | ** ** |
| $                                    | 65,033     |   | $ | 64,622 |   | $ | 65,970 |   | $ | 64,778 |   |
| **March 31, 2005**                   | ** ** | **June 30, 2005** | ** ** | **Sept. 30, 2005** | ** ** | **Dec. 31, 2005** | ** ** |
| $                                    | —     |   | $ | — |   | $ | — |   | $ | — |   |

 

**Item6**— **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).

**Item7**— **Management’s Discussionand Analysis 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 discussionand analysis by management focuses on those factors that had a material effecton the 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 Financial Statementsand 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 statements are intended to be identified in thisdocument 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, includingthe availability of credit and its impact on capital expenditures and theability of PSCo to obtain financing on favorable terms; business conditions in the energy industry; actions of creditrating agencies; competitive factors, including the extent and timing of theentry of additional competition in the markets served by PSCo; unusual weather;effects of geopolitical events, including war and acts of terrorism; state,federal and foreign legislative and regulatory initiatives that affect cost andinvestment recovery, have an impact on rates or have an impact on assetoperation or ownership, structures that affect the speed and degree to whichcompetition enters the electric and natural gas markets; costs and othereffects of legal and administrative proceedings, settlements, investigationsand claims; actions of accounting regulatory bodies; the items described under “RiskFactors” in Item 1A and Exhibit 99.01 of PSCo’s Form 10-K for the yearended Dec. 31, 2006.

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**Management’s Discussion andAnalysis of Financial Condition and Results of Operation**

**ResultsOf Operations**

PSCo’s net income wasapproximately $241.5 million for 2006, compared with approximately $211.4million for 2005.

***Electric Utility, Short-TermWholesale and Commodity Trading Margins***

Electric fuel and purchased power expenses tend tovary with changing retail and wholesale sales requirements and unit costchanges in fuel and purchased power.  Dueto fuel and purchased energy cost-recovery mechanisms for customers, mostfluctuations in these costs do not materially affect electric utility margin.

PSCo has two distinctforms of wholesale sales: short-term wholesale and commodity trading.  Short-term wholesale refers to energy-relatedpurchase and sales activity and the use of certain financial instruments associatedwith the fuel required for, and energy produced from, PSCo’s generation assetsor the energy and capacity purchased to serve native load.  Commodity trading is not associated with PSCo’sgeneration assets or the energy and capacity purchased to serve nativeload.  Short-term wholesale and commoditytrading activities are considered part of the electric utility segment.

Margins from commoditytrading activity conducted at PSCo are partially redistributed to NSP-Minnesotaand SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the JOAapproved by the FERC.  Margins receivedpursuant to the JOA are reflected as part of Base Electric UtilityRevenue.  Short-term wholesale andcommodity trading margins reflect the impact of regulatory sharing, ifapplicable. Trading revenues, as discussed in Note 1 to the ConsolidatedFinancial Statements, are reported net of related costs (i.e., on a marginbasis) in the Consolidated Statements of Income. Commodity trading costsinclude purchased power, transmission, broker fees and other related costs.  Short-term wholesale and commodity tradingmargins reflect the estimated impact of regulatory sharing of margins, ifapplicable.

The following tabledetails the revenue and margin for base electric utility, short-term wholesaleand commodity trading activities:

 
| ** **                                              | ** ** | **Base**     | ** ** | ** **     | ** ** | ** **    | ** ** | ** **       | ** ** |
|---------------------------------------------------------|------------|--------------|------------|----------------|------------|---------------|------------|------------------|------------|
| ** **                                              | ** ** | **Electric** | ** ** | **Short-Term** | ** ** | **Commodity** | ** ** | **Consolidated** | ** ** |
| **(Millions of Dollars)**                     | ** ** | **Utility**  | ** ** | **Wholesale**  | ** ** | **Trading**   | ** ** | **Totals**       | ** ** |
| **2006**                                                |       |         |       |           |       |          |       |             |       |
| Electric utility  revenue (excluding commodity trading) |       | $            | 2,472      |           | $          | 29            |       | $                | —     |   | $ | 2,501 |   |
| Fuel and purchased  power                               |       | (1,465       | )          | (25            | )          | —        |       | (1,490           | )          |
| Commodity  trading revenue                              |       | —       |       | —         |       | 466           |       | 466              |       |
| Commodity  trading costs                                |       | —       |       | —         |       | (461          | )          | (461             | )          |
| Gross margin before operating expenses                  |       | $            | 1,007      |           | $          | 4             |       | $                | 5          |   | $ | 1,016 |   |
| Margin as a  percentage of revenue                      |       | 40.7         | %          | 13.8           | %          | 1.1           | %          | 34.2             | %          |
|                                                    |       |         |       |           |       |          |       |             |       |
| **2005**                                                |       |         |       |           |       |          |       |             |       |
| Electric utility  revenue (excluding commodity trading) |       | $            | 2,486      |           | $          | 17            |       | $                | —     |   | $ | 2,503 |   |
| 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             | %          |

 

The following summarizesthe components of the changes in base electric revenue and base electric marginfor the year ended Dec. 31:

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***Base Electric Revenue***

| (Millions of Dollars)         | ** ** | **2006 vs 2005** | ** ** |
|-----------------------------------------|------------|----------------------------|------------|
| Sales growth                            |       | $                          | 12         |   |
| Non-fuel riders                         |       | 11                         |       |
| Service quality  adjustment             |       | 8                          |       |
| Gain on sale of  SO2 allowances         |       | 4                          |       |
| Retail fuel cost  recovery              |       | (15                        | )          |
| Firm wholesale  revenue, including fuel |       | (13                        | )          |
| Sales mix                               |       | (10                        | )          |
| Capacity sales                          |       | (10                        | )          |
| Other                                   |       | (1                         | )          |
| Total base  electric revenue decrease   |       | $                          | (14        | ) |

*** ***

***Base Electric Margin***

| (Millions of Dollars)         | ** ** | **2006 vs 2005** | ** ** |
|-----------------------------------------|------------|----------------------------|------------|
| Fuel and  purchased power cost recovery |       | $                          | 21         |   |
| Sales growth                            |       | 12                         |       |
| Non-fuel riders                         |       | 11                         |       |
| Service quality  adjustment             |       | 8                          |       |
| Gain on sale of  SO2 allowances         |       | 4                          |       |
| ECA incentive                           |       | (20                        | )          |
| Fuel handling  & procurement costs  |       | (10                        | )          |
| Capacity sales                          |       | (10                        | )          |
| Sales mix and  other                    |       | (4                         | )          |
| Total base  electric margin increase    |       | $                          | 12         |   |

 

***Natural Gas Utility Revenue and Margins*****— The following table details the changein natural 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)                | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| Natural gas  utility revenue                   |       | $        | 1,262      |     | $          | 1,329 |   |
| Cost of natural  gas purchased and transported |       | (938     | )          | (1,032   | )          |
| Natural gas utility margin                     |       | $        | 324        |     | $          | 297 |   |

 

The following summarizesthe components of the changes in natural gas revenue and margin for the yearended Dec. 31:

***Natural Gas Revenue***

| (Millions of Dollars)           | ** ** | **2006 vs 2005** | ** ** |
|-------------------------------------------|------------|----------------------------|------------|
| Base rate change                          |       | $                          | 18         |   |
| Transportation                            |       | 9                          |       |
| Sales growth  (excluding weather impact)  |       | 2                          |       |
| Purchased gas  adjustment clause recovery |       | (87                        | )          |
| Other                                     |       | (9                         | )          |
| Total natural  gas revenue decrease       |       | $                          | (67        | ) |

 

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

| (Millions of Dollars)          | ** ** | **2006 vs 2005** | ** ** |
|------------------------------------------|------------|----------------------------|------------|
| Base rate change                         |       | $                          | 18         |   |
| Transportation                           |       | 8                          |       |
| Sales growth  (excluding weather impact) |       | 1                          |       |
| Estimated impact  of weather             |       | 1                          |       |
| Other                                    |       | (1                         | )          |
| Total natural  gas margin increase       |       | $                          | 27         |   |

 

24

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***Non-Fuel Operating Expense and Other Costs****—*Other operating and maintenance expensesfor 2006 increased $22 million, or 4.1 percent, compared to 2005.  The following summarizes the components ofthe changes for the year ended Dec. 31:

| (Millions of Dollars)                   | ** ** | **2006 vs 2005** | ** ** |
|---------------------------------------------------|------------|----------------------------|------------|
| Higher employee  benefit costs                    |       | $                          | 19         |   |
| Higher plant  costs                               |       | 7                          |       |
| Higher materials  costs                           |       | 2                          |       |
| Higher  uncollectible receivable costs            |       | 2                          |       |
| Higher  transportation fleet costs                |       | 2                          |       |
| Lower  consulting/contractor costs                |       | (6                         | )          |
| Gains/losses on  sale or disposals of assets, net |       | (6                         | )          |
| Other                                             |       | 2                          |       |
| Total non-fuel operating  expense increase        |       | $                          | 22         |   |

 

Depreciation andamortization expense increased by approximately $1.5 million, or 0.6 percent,for 2006 compared with 2005, primarily due to plant additions and higherregulatory amortization of demand side management costs, offset by loweramortization related to Fort. St. Vrain which was fully amortized at the end of2005.

Taxes (other than incometaxes) decreased by approximately $2.6 million, or 2.8 percent, for 2006compared with 2005, primarily due to lower property taxes relating to a changein 2005 valuation and the 2006 estimate.

Interest and other income(expense), net, decreased by approximately $2.3 million primarily due to higherinterest expense on COLI loans, partially offset by higher interest income fromthe COLI life insurance investments.

Interest charges and financing costs decreased byapproximately $7.3 million, or 5.1 percent, for 2006 compared with 2005,primarily due to the retirement of long-term debt in November 2005 and June2006, partially offset with increased short-term borrowings.

AFDC is an amountcapitalized as a part of construction costs representing the cost of financingthe construction.  Generally, these costsare recovered from customers as the related property is depreciated.  Of this amount, debt related AFDC increasedby approximately $8.8 million and equity related AFDC was consistent with 2005levels.

Incometax expense increased by approximately $11.5 million in 2006, compared with2005.  The increase was primarily due tohigher pretax income.  The effective taxrate was 25.3 percent for 2006, compared with 24.9 percent for 2005.

**Item7A**— **Quantitative andQualitative Disclosures About Market Risk**

**Derivatives,Risk Management and Market Risk**

In thenormal course of business, PSCo is exposed to a variety of market risks.  Market risk is the potential loss that mayoccur as a result of changes in the market or fair value of a particularinstrument or commodity.  All financialand commodity related instruments, including derivatives, are subject to marketrisk.  These risks, as applicable toPSCo, are discussed in further detail below.

***Commodity Price Risk —*** PSCo is exposedto commodity price risk in its electric and natural gas 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 generation and distribution activities. Commodity price risk is also managed through the use of financialderivative instruments.  PSCo’s riskmanagement policy allows it to manage commodity price risk within eachrate-regulated operation to the extent such exposure exists, as allowed byregulation.

***Short-Term Wholesale and Commodity Trading Risk —***PSCoconducts various short-term wholesale and commodity trading activities,including the purchase and sale of capacity, energy and energy relatedinstruments. These marketing activities generally have terms of less than oneyear in length.  PSCo’s risk managementpolicy allows management to conduct the marketing activities within guidelinesand limitations as approved by the company’s risk management committee, whichis made up of management personnel not directly involved in the activitiesgoverned by the policy.

Certain contracts withinthe scope of these activities qualify for hedge accounting treatment under SFASNo. 133 — “Accounting for Derivative Instruments and Hedging Activities”.

See Note 9 to theConsolidated Financial Statements for a discussion of the various trading andhedging contracts of PSCo.

PSCo’s short-termwholesale and commodity trading operations measure the outstanding riskexposure to price changes on transactions, contracts and obligations that havebeen entered into, but not closed, using an industry standard methodology

25

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known as Value-at-Risk(VaR). VaR expresses the potential change in fair value on the outstandingtransactions, contracts and obligations over a particular period of time, witha given confidence 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.

VaR is calculated on aconsolidated basis.  The VaRs for thecommodity trading operations were:

 
| ** **                      | ** ** | **Year ended**         | ** ** | **During 2006** | ** ** |
|---------------------------------|------------|-----------------------------|------------|----------------------|------------|
| (Millions of Dollars) | ** ** | **Dec. 31, 2006** | ** ** | **Average**          | ** ** | **High** | ** ** | **Low** | ** ** |
| ** **                      | ** ** | ** **                  | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Commodity trading (a)           |       | $                           | 0.49       |                 | $          | 1.32 |   | $ | 2.60 |   | $ | 0.39 |   |
|                                 |            |                             |            |                      |            |  |  |  |  |  |  |  |  |

 
| ** **                      | ** ** | **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)             Comprisestransactions for NSP-Minnesota, PSCo and SPS.

***Interest Rate Risk —***PSCois subject to the risk of fluctuating interest rates in the normal course ofbusiness.  PSCo’s risk management policyallows interest rate risk to be managed through the use of fixed rate debt,floating rate debt and interest rate derivatives such as swaps, caps, collarsand put or call options, 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 or losseson cash flow hedges of variable rate debt instruments from Other ComprehensiveIncome into earnings occurs as interest payments are accrued on the debtinstrument, and generally offsets the change in the interest accrued on theunderlying variable rate debt.  Hedges offair value exposure are entered into to hedge the fair value of debtinstruments.  Changes in the derivativefair values that are designated as fair value hedges are recognized in earningsas offsets to the changes in fair values of debt instruments.  To test the effectiveness of such swaps, ahypothetical swap is used to mirror all the critical terms of the underlyingdebt and regression analysis is utilized to assess the effectiveness of theactual swap at inception and on an ongoing basis.  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, 2006 and 2005, a 100-basis-point change in the benchmark rate on PSCo’svariable rate debt would impact pretax interest expense by approximately $3.2million and $1.9 million, respectively.

***Credit Risk —***In addition to the risksdiscussed previously, PSCo is also exposed to credit risk. Credit risk relatesto the risk of loss resulting from the nonperformance by a counterparty of itscontractual obligations. PSCo maintains credit policies intended to minimizeoverall credit risk and actively monitors these policies to reflect changes andscope of operations.

PSCo conducts standardcredit reviews for all counterparties. PSCo employs additional credit riskcontrol mechanisms when appropriate, such as letters of credit, parentalguarantees, standardized master netting agreements and termination provisionsthat allow for offsetting of positive and negative exposures. The creditexposure is monitored and, when necessary, the activity with a specificcounterparty is limited until credit enhancement is provided.

**Item8**— **Financial Statementsand Supplementary Data**

26

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**REPORT OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

Boardof Directors and Stockholder

PublicService Company of Colorado

We have audited the accompanying consolidatedbalance sheets and statements of capitalization of Public Service Company ofColorado and subsidiaries (the “Company”) as of December 31, 2006 and 2005, andthe related consolidated statements of income, common stockholder’s equity andcomprehensive income and cash flows for each of the three years in the periodended December 31, 2006.  Our audits also included the financial statementschedule listed in the Index at Item 15. These financial statements andfinancial statement schedule are the responsibility of the Company’smanagement.  Our responsibility is to express an opinion on the financialstatements and financial statement schedule based on our audits.

We conducted our audits in accordance withthe standards of the Public Company Accounting Oversight Board (UnitedStates).  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 weengaged to perform, an audit of its internal control over financialreporting.  Our audits included consideration of internal control overfinancial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting.  Accordingly, we express no such opinion.  An audit alsoincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, as well as evaluating theoverall financial statement presentation.  We believe that our auditsprovide a reasonable basis for our opinion.

In our opinion, such consolidated financialstatements present fairly, in all material respects, the financial position ofPublic Service Company of Colorado and subsidiaries as of December 31, 2006 and2005, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2006, in conformity withaccounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered inrelation to the basic consolidated financial statements taken as a whole,presents fairly in all material respects the information set forth therein.

As discussed in Note 7 to the consolidatedfinancial statements, the Company adopted Statement of Financial AccountingStandards No. 158, “Employers’ Accounting for Defined Benefit Pension andOther Postretirement Plans,” as of December 31, 2006.

 
| /S/ DELOITTE & TOUCHE  LLP |   |
|--------------------------------|--------|
| Minneapolis,  Minnesota        |   |
| February 22,  2007             |   |

 

27

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**PUBLICSERVICE CO. OF COLORADO**

**CONSOLIDATED STATEMENTS OF INCOME**

**(Thousandsof Dollars)**

 
| ** **                                                                                     | ** ** | **Year Ended Dec. 31** | ** ** |
|------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                     | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Operating revenues**                                                                         |       |                                  |       |   |   |   |   |
| Electric utility                                                                               |       | $                                     | 2,505,445  |   | $ | 2,504,028 |   | $ | 2,194,628 |   |
| Natural gas  utility                                                                           |       | 1,262,295                             |       | 1,329,034 |   | 1,073,989 |   |
| Steam and other                                                                                |       | 38,089                                |       | 33,501 |   | 27,825 |   |
| Total operating  revenues                                                                      |       | 3,805,829                             |       | 3,866,563 |   | 3,296,442 |   |
|                                                                                           |       |                                  |       |   |   |   |   |
| **Operating expenses**                                                                         |       |                                  |       |   |   |   |   |
| Electric fuel  and purchased power                                                             |       | 1,489,714                             |       | 1,507,248 |   | 1,242,684 |   |
| Cost of natural  gas sold and transported                                                      |       | 938,380                               |       | 1,032,504 |   | 785,055 |   |
| Cost of sales —  steam and other                                                          |       | 21,043                                |       | 19,231 |   | 17,383 |   |
| Operating and  maintenance expenses                                                            |       | 569,059                               |       | 546,608 |   | 510,157 |   |
| Depreciation and  amortization                                                                 |       | 239,916                               |       | 238,402 |   | 223,442 |   |
| Taxes (other  than income taxes)                                                               |       | 88,878                                |       | 91,438 |   | 86,671 |   |
| Total operating  expenses                                                                      |       | 3,346,990                             |       | 3,435,431 |   | 2,865,392 |   |
|                                                                                           |       |                                  |       |   |   |   |   |
| **Operating income**                                                                           |       | 458,839                               |       | 431,132 |   | 431,050 |   |
|                                                                                           |       |                                  |       |   |   |   |   |
| Interest and  other income (expense), net (see Note 8)                                         |       | (14,223                               | )          | (11,884 | ) | 24 |   |
| Allowance for  funds used during construction - equity                                         |       | 2,650                                 |       | 2,655 |   | 9,809 |   |
|                                                                                           |       |                                  |       |   |   |   |   |
| **Interest charges and financing  costs**                                                      |       |                                  |       |   |   |   |   |
| Interest charges  — including financing costs of $6,029, $6,744, and $7,353, respectively |       | 137,493                               |       | 144,835 |   | 157,447 |   |
| Allowance for  funds used during construction - debt                                           |       | (13,386                               | )          | (4,589 | ) | (7,425 | ) |
| Total interest  charges and financing costs                                                    |       | 124,107                               |       | 140,246 |   | 150,022 |   |
|                                                                                           |       |                                  |       |   |   |   |   |
| Income before income  taxes                                                                    |       | 323,159                               |       | 281,657 |   | 290,861 |   |
| Income taxes                                                                                   |       | 81,701                                |       | 70,240 |   | 72,856 |   |
| Net income                                                                                     |       | $                                     | 241,458    |   | $ | 211,417 |   | $ | 218,005 |   |

 

SeeNotes to Consolidated Financial Statements

28

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**PUBLICSERVICE CO. OF COLORADO**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(Thousands of Dollars)**

 
| ** **                                                                     | ** ** | **Year Ended Dec. 31** | ** ** |
|--------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                     | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Operating  activities**                                                      |       |                                  |       |   |   |   |   |
| Net income                                                                     |       | $                                     | 241,458    |   | $ | 211,417 |   | $ | 218,005 |   |
| Adjustments to reconcile net income to cash provided  by operating activities: |       |                                  |       |   |   |   |   |
| Depreciation and amortization                                                  |       | 253,725                               |       | 251,668 |   | 234,164 |   |
| Deferred income taxes                                                          |       | 76,040                                |       | 111,455 |   | 79,493 |   |
| Amortization of investment tax credits                                         |       | (3,949                                | )          | (3,971 | ) | (4,000 | ) |
| Allowance for equity funds used during construction                            |       | (2,650                                | )          | (2,655 | ) | (9,809 | ) |
| Unrealized (gain) loss on derivative instruments                               |       | (136                                  | )          | (2,990 | ) | 1,557 |   |
| Change in accounts receivable                                                  |       | 133,691                               |       | (137,782 | ) | (107,652 | ) |
| Change in accrued unbilled revenues                                            |       | 35,253                                |       | (61,760 | ) | (17,819 | ) |
| Change in inventories                                                          |       | 34,865                                |       | (56,043 | ) | (31,781 | ) |
| Change in recoverable purchased natural gas and  electric energy costs         |       | 72,566                                |       | (58,178 | ) | (27,068 | ) |
| Change in prepayments and other current assets                                 |       | (27,728                               | )          | 17,773 |   | (3,117 | ) |
| Change in accounts payable                                                     |       | (187,571                              | )          | 154,481 |   | 22,894 |   |
| Change in other current liabilities                                            |       | 25,032                                |       | 6,193 |   | (5,222 | ) |
| Change in other noncurrent assets                                              |       | (53,057                               | )          | (43,506 | ) | 32,226 |   |
| Change in other noncurrent liabilities                                         |       | (14,998                               | )          | (309 | ) | (44,812 | ) |
| Net cash provided by operating activities                                      |       | 582,541                               |       | 385,793 |   | 337,059 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| **Investing  activities**                                                      |       |                                  |       |   |   |   |   |
| Capital/construction expenditures                                              |       | (537,920                              | )          | (424,292 | ) | (457,365 | ) |
| Proceeds from disposition of property, plant and  equipment                    |       | —                                |       | — |   | 11,682 |   |
| Allowance for equity funds used during construction                            |       | 2,650                                 |       | 2,655 |   | 9,809 |   |
| Other investments                                                              |       | 9,869                                 |       | 6,520 |   | (1,691 | ) |
| Net cash used in investing activities                                          |       | (525,401                              | )          | (415,117 | ) | (437,565 | ) |
|                                                                           |       |                                  |       |   |   |   |   |
| **Financing  activities**                                                      |       |                                  |       |   |   |   |   |
| Short-term borrowings — net                                               |       | 36,896                                |       | 138,649 |   | 182,914 |   |
| Proceeds from issuance of long-term debt                                       |       | —                                |       | 129,500 |   | — |   |
| Borrowings under utility money pool arrangement                                |       | 1,426,800                             |       | — |   | — |   |
| Repayments under utility money pool arrangement                                |       | (1,426,800                            | )          | — |   | — |   |
| Borrowings under 5-year unsecured credit facility                              |       | —                                |       | 293,000 |   | — |   |
| Repayments under 5-year unsecured credit facility                              |       | —                                |       | (293,000 | ) | — |   |
| Repayment of long-term debt, including reacquisition  premiums                 |       | (126,334                              | )          | (375,354 | ) | (147,000 | ) |
| Capital contribution from parent                                               |       | 227,272                               |       | 202,029 |   | 184,123 |   |
| Dividends paid to parent                                                       |       | (195,625                              | )          | (62,564 | ) | (243,906 | ) |
| Net cash provided by (used in) financing activities                            |       | (57,791                               | )          | 32,260 |   | (23,869 | ) |
|                                                                           |       |                                  |       |   |   |   |   |
| Net increase  (decrease) in cash and cash equivalents                          |       | (651                                  | )          | 2,936 |   | (124,375 | ) |
| Cash and cash  equivalents at beginning of year                                |       | 3,662                                 |       | 726 |   | 125,101 |   |
| Cash and cash  equivalents at end of year                                      |       | $                                     | 3,011      |   | $ | 3,662 |   | $ | 726 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| Supplemental  disclosure of cash flow information:                             |       |                                  |       |   |   |   |   |
| Cash paid for  interest (net of amounts capitalized)                           |       | $                                     | 125,284    |   | $ | 139,414 |   | $ | 151,424 |   |
| Cash paid for  income taxes (net of refunds received)                          |       | $                                     | (6,640     | ) | $ | (16,042 | ) | $ | 16,203 |   |
|                                                                           |       |                                  |       |   |   |   |   |
| Supplemental  disclosure of non-cash investing transactions:                   |       |                                  |       |   |   |   |   |
| Property, plant  and equipment additions in accounts payable                   |       | $                                     | 5,367      |   | $ | 13,404 |   | $ | 14,291 |   |

 

SeeNotes to Consolidated Financial Statements

29

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**PUBLICSERVICE CO. OF COLORADO**

**CONSOLIDATED BALANCE SHEETS**

**(Thousandsof Dollars)**

** **
| ** **                                                                                    | ** ** | **Dec. 31, 2006** | ** ** | **Dec. 31, 2005** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **ASSETS**                                                                                    |       |                        |       |                        |       |
| Current assets:                                                                               |       |                        |       |                        |       |
| Cash and cash equivalents                                                                     |       | $                           | 3,011      |                        | $          | 3,662 |   |
| Accounts receivable — net of allowance for bad  debts: $18,415 and $19,381, respectively |       | 355,738                     |       | 451,944                     |       |
| Accounts receivable from affiliates                                                           |       | 8,621                       |       | 47,746                      |       |
| Accrued unbilled revenues                                                                     |       | 199,361                     |       | 234,614                     |       |
| Recoverable purchased natural gas and electric  energy costs                                  |       | 157,827                     |       | 230,393                     |       |
| Materials and supplies inventories — at average cost                                     |       | 43,029                      |       | 42,602                      |       |
| Fuel inventory — at average cost                                                         |       | 40,997                      |       | 19,582                      |       |
| Natural gas inventory — at average cost                                                  |       | 155,567                     |       | 212,274                     |       |
| Derivative instruments valuation-at market                                                    |       | 28,111                      |       | 78,064                      |       |
| Deferred income taxes                                                                         |       | 62,791                      |       | 19,781                      |       |
| Prepayments and other                                                                         |       | 14,654                      |       | 15,437                      |       |
| Total current assets                                                                          |       | 1,069,707                   |       | 1,356,099                   |       |
| Property, plant  and equipment, at cost:                                                      |       |                        |       |                        |       |
| Electric utility plant                                                                        |       | 6,409,194                   |       | 6,275,046                   |       |
| Natural gas utility plant                                                                     |       | 1,825,560                   |       | 1,793,240                   |       |
| Common utility and other property                                                             |       | 725,864                     |       | 745,894                     |       |
| Construction work in progress                                                                 |       | 429,878                     |       | 209,721                     |       |
| Total property, plant and equipment                                                           |       | 9,390,496                   |       | 9,023,901                   |       |
| Less accumulated depreciation                                                                 |       | (2,912,233                  | )          | (2,854,757                  | )          |
| Net property, plant and equipment                                                             |       | 6,478,263                   |       | 6,169,144                   |       |
| Other assets:                                                                                 |       |                        |       |                        |       |
| Regulatory assets                                                                             |       | 589,016                     |       | 231,801                     |       |
| Derivative instruments valuation-at market                                                    |       | 161,502                     |       | 164,251                     |       |
| Other investments                                                                             |       | 19,347                      |       | 29,465                      |       |
| Other                                                                                         |       | 45,784                      |       | 35,191                      |       |
| Total other assets                                                                            |       | 815,649                     |       | 460,708                     |       |
| Total assets                                                                                  |       | $                           | 8,363,619  |                        | $          | 7,985,951 |   |
|                                                                                          |       |                        |       |                        |       |
| **LIABILITIES  AND EQUITY**                                                                   |       |                        |       |                        |       |
| Current  liabilities:                                                                         |       |                        |       |                        |       |
| Current portion of long-term debt                                                             |       | $                           | 101,379    |                        | $          | 126,334 |   |
| Short-term debt                                                                               |       | 372,500                     |       | 335,604                     |       |
| Accounts payable                                                                              |       | 385,724                     |       | 578,722                     |       |
| Accounts payable to affiliates                                                                |       | 30,291                      |       | 26,388                      |       |
| Taxes accrued                                                                                 |       | 84,960                      |       | 81,638                      |       |
| Dividends payable to parent                                                                   |       | 64,778                      |       | —                      |       |
| Derivative instruments valuation-at market                                                    |       | 38,616                      |       | 66,463                      |       |
| Accrued interest                                                                              |       | 35,362                      |       | 36,498                      |       |
| Other                                                                                         |       | 74,381                      |       | 71,206                      |       |
| Total current liabilities                                                                     |       | 1,187,991                   |       | 1,322,853                   |       |
| Deferred credits  and other liabilities:                                                      |       |                        |       |                        |       |
| Deferred income taxes                                                                         |       | 1,004,027                   |       | 811,961                     |       |
| Deferred investment tax credits                                                               |       | 59,035                      |       | 62,984                      |       |
| Regulatory liabilities                                                                        |       | 470,255                     |       | 492,335                     |       |
| Pension and Employee Benefit Obligations                                                      |       | 301,277                     |       | 148,255                     |       |
| Customers advances for construction                                                           |       | 279,011                     |       | 288,397                     |       |
| Asset retirement obligations                                                                  |       | 43,335                      |       | 41,968                      |       |
| Derivative instruments valuation-at market                                                    |       | 156,623                     |       | 170,849                     |       |
| Other liabilities                                                                             |       | 7,750                       |       | 18,387                      |       |
| Total deferred credits and other liabilities                                                  |       | 2,321,313                   |       | 2,035,136                   |       |
| Commitments and  contingent liabilities (see Note 12)                                         |       |                        |       |                        |       |
| Capitalization  (See Statements of Capitalization):                                           |       |                        |       |                        |       |
| Long-term debt                                                                                |       | 1,845,278                   |       | 1,945,973                   |       |
| Common stock — authorized 100 shares of $0.01 par  value; outstanding 100 shares         |       | —                      |       | —                      |       |
| Additional paid in capital                                                                    |       | 2,411,204                   |       | 2,183,932                   |       |
| Retained earnings                                                                             |       | 585,219                     |       | 604,163                     |       |
| Accumulated other comprehensive income (loss)                                                 |       | 12,614                      |       | (106,106                    | )          |
| Total common stockholder’s equity                                                        |       | 3,009,037                   |       | 2,681,989                   |       |
| Total  liabilities and equity                                                                 |       | $                           | 8,363,619  |                        | $          | 7,985,951 |   |

 

SeeNotes to Consolidated Financial Statements

30

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**PUBLICSERVICE CO. OF COLORADO**

## **CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’SEQUITYAND COMPREHENSIVE INCOME**

**(Dollarsin Thousands)**

 
| ** **                                                                            | ** ** | ** **            | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **        | ** ** | **Accumulated**        | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------|------------|-----------------------|------------|----------------|------------|-------------------------------|------------|-------------------|------------|------------------------|------------|------------|------------|
| ** **                                                                            | ** ** | ** **            | ** ** | ** **     | ** ** | ** **                    | ** ** | ** **        | ** ** | **Other**              | ** ** | **Total**  | ** ** |
| ** **                                                                            | ** ** | **Common Stock** | ** ** | **Additional** | ** ** | **Retained**                  | ** ** | **Comprehensive** | ** ** | **Stockholder’s** | ** ** |
| ** **                                                                            | ** ** | **Shares**            | ** ** | **Amount**     | ** ** | **Paid in Capital** | ** ** | **Earnings**      | ** ** | **Income (loss)** | ** ** | **Equity** | ** ** |
| **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 tax of $(4,202) (see Note 7)            |       |                  |       |           |       |                          |       |              |       | (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 tax of $(9,898) (see Note 7)            |       |                  |       |           |       |                          |       |              |       | (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 |   |
| Net income                                                                            |       |                  |       |           |       |                          |       | 241,458           |       |                   |       | 241,458    |       |
| Minimum pension  liability adjustment, net of tax of $19,239 (see Note 7)             |       |                  |       |           |       |                          |       |              |       | 31,589                 |       | 31,589     |       |
| Net derivative  instrument fair value changes during the period, net of tax of $(981) |       |                  |       |           |       |                          |       |              |       | (1,607                 | )          | (1,607     | )          |
| Unrealized loss  — marketable securities, net of tax of $(46)                    |       |                  |       |           |       |                          |       |              |       | (75                    | )          | (75        | )          |
| Comprehensive  income for 2006                                                        |       |                  |       |           |       |                          |       |              |       |                   |       | 271,365    |       |
| SFAS No. 158  adoption, net of tax of $53,995                                         |       |                  |       |           |       |                          |       |              |       | 88,813                 |       | 88,813     |       |
| Common dividends  declared to parent                                                  |       |                  |       |           |       |                          |       | (260,402          | )          |                   |       | (260,402   | )          |
| Contribution of  capital by parent                                                    |       |                  |       |           |       | 227,272                       |       |              |       |                   |       | 227,272    |       |
| **Balance at Dec. 31, 2006**                                                          |       | 100                   |       | $              | —     |                          | $          | 2,411,204         |       | $                      | 585,219    |       | $          | 12,614 |   | $ | 3,009,037 |   |

 

SeeNotes to Consolidated Financial Statements

31

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**PUBLICSERVICE CO. OF COLORADO**

**CONSOLIDATED STATEMENTS OF CAPITALIZATION**

**(Thousands of Dollars)**

 
| ** **                                                                                             | ** ** | **Dec. 31** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                             | ** ** | **2006**         | ** ** | **2005** | ** ** |
| **Long-Term  Debt**                                                                                    |       |             |       |   |   |
| First Mortgage  Bonds, Series due:                                                                     |       |             |       |   |   |
| June 1, 2006, 7.125%                                                                                   |       | $                | —     |   | $ | 125,000 |   |
| Oct. 1, 2008, 4.375%                                                                                   |       | 300,000          |       | 300,000 |   |
| 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 |   |
| Sept. 1, 2017, 4.375% (a)                                                                              |       | 129,500          |       | 129,500 |   |
| Jan. 1, 2019, 5.1% (a)                                                                                 |       | 48,750           |       | 48,750 |   |
| 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                                     |       | 46,247           |       | 47,581 |   |
| Unamortized  discount                                                                                  |       | (2,840           | )          | (3,524 | ) |
| Total                                                                                                  |       | 1,946,657        |       | 2,072,307 |   |
| Less current  maturities                                                                               |       | 101,379          |       | 126,334 |   |
| Total long-term debt                                                                                   |       | $                | 1,845,278  |   | $ | 1,945,973 |   |
|                                                                                                   |       |             |       |   |   |
| **Common  Stockholder’s Equity**                                                                  |       |             |       |   |   |
| Common stock — authorized 100 shares of $0.01 par  value; outstanding 100 shares in 2006 and 2005 |       | $                | —     |   | $ | — |   |
| Additional paid in capital                                                                             |       | 2,411,204        |       | 2,183,932 |   |
| Retained earnings                                                                                      |       | 585,219          |       | 604,163 |   |
| Accumulated other comprehensive income (loss)                                                          |       | 12,614           |       | (106,106 | ) |
| Total common  stockholder’s equity                                                                |       | $                | 3,009,037  |   | $ | 2,681,989 |   |

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(a)             Pollutioncontrol financing.

SeeNotes to Consolidated Financial Statements

32

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**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS**

**1.Summary of Significant Accounting Policies**

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

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

***Revenue Recognition*****— Revenues related to the sale of energyare generally recorded when service is rendered or energy is delivered tocustomers. However, the determination of the energy sales to individualcustomers is based on the reading of their meters, which occurs on a systematicbasis throughout the month. At the end of each month, amounts of energydelivered to customers since the date of the last meter reading are estimatedand the corresponding unbilled revenue is estimated.

PSCo has variousrate-adjustment 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 of significantrate adjustment mechanisms follows:

·       PSCogenerally recovers all prudently incurred electric fuel and purchased energycosts through the ECA.  The ECA,effective Jan. 1, 2004, is an incentive adjustment mechanism that comparesactual fuel and purchased energy expense in a calendar year to a benchmarkformula. The ECA also provides for an $11.25 million cap on any cost sharingover or under an allowed ECA formula rate. The current ECA mechanism expiredDec. 31, 2006.  Effective Jan. 1, 2007the ECA has been modified to include an incentive adjustment to encourageefficient operation of base load coal plants and encourage cost reductionsthrough purchases of economical short-term energy.  The total incentive payment to PSCo in anycalendar year will not exceed $11.25 million. The ECA mechanism will be revised quarterly and interest will accruemonthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche3 is placed in service or Dec. 31, 2010.

·       In Colorado, PSCo operatesunder an annual earnings test in which earnings above the authorized return onequity are refunded to customers.  PSCooperates under various service quality standards, which could require customerrefunds if certain criteria are not met. PSCo’s rates also include monthlyadjustments for the recovery of conservation and energy-management programcosts, which are reviewed annually.  PSCois allowed to recover certain costs associated with renewable energy resourcesthrough a specific retail rate rider.

·       PSCo sells firm power andenergy in wholesale markets, which are regulated by the FERC. Certain of theserates include monthly wholesale fuel cost-recovery mechanisms.

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

Pursuant to the JOAapproved by the FERC, some of the commodity trading margins from PSCo areapportioned to NSP-Minnesota and SPS. Commodity trading activities are notassociated with energy produced from PSCo’s generation assets or energy andcapacity purchased to serve native load. Commodity trading contracts arerecorded at fair market value in accordance with SFAS 133. In addition,commodity trading results include the impacts of all pertinent margin-sharingmechanisms. For more information, see Note 9 to the Consolidated FinancialStatements.

***Derivative Financial Instruments****—*PSCo utilizes a variety of derivatives,including commodity forwards, futures and options, index or fixed price swapsand basis swaps, to mitigate market risks and to enhance its operations.  For further discussion of PSCo’s riskmanagement and derivative activities see Note 9 to the Consolidated FinancialStatements.

***Property, Plant, and Equipment and Depreciation*****— Property, plant and equipment is statedat original 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 repair and maintenance costs are charged to expense asincurred. Maintenance and replacement of items determined to be less than unitsof property are charged to operating expenses as incurred. Planned majormaintenance activities are charged to 

33

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operating expense unlessthe cost represents the acquisition of an additional unit of property or thereplacement of an existing unit of property. Property, plant and equipment also includes costs associated with otherproperty held for future use.

PSCo records depreciationexpense related to its plant by using the straight-line method over the plant’suseful life. Actuarial and semi-actuarial life studies are performed on aperiod basis and submitted to the state and federal commissions forreview.  Upon acceptance by the variouscommissions, the resulting lives and net salvage rates are used to calculatedepreciation.  Depreciation expense,expressed as a percentage of average depreciable property, for the years ended Dec.31, 2006, 2005 and 2004 was 2.6 percent, 2.6 percent and 2.5 percent,respectively.

***AFDC*****— AFDC represents the cost of capital used to finance utilityconstruction activity. AFDC is computed by applying a composite pretax rate toqualified construction work in progress. The amount of AFDC capitalized as autility construction cost is credited to other income (for equity capital) andinterest charges (for debt capital). AFDC amounts capitalized are included inPSCo’s rate base for establishing utility service rates.

***Environmental Costs*****— Environmental costs are recorded on anundiscounted basis when it is probable PSCo is liable for the costs and theliability can be reasonably estimated. Costs may be deferred as a regulatoryasset if it is probable that the costs will be recovered from customers infuture rates. Otherwise, the costs are expensed. If an environmental expense isrelated to facilities currently in use, such as emission-control equipment, thecost is capitalized and depreciated over the life of the plant, assuming thecosts are recoverable in future rates or future cash flow.

Estimated remediationcosts, excluding inflationary increases, are recorded. The estimates are basedon experience, an assessment of the current situation and the technologycurrently available for use in the remediation. The recorded costs areregularly adjusted as estimates are revised and remediation proceeds. Ifseveral designated responsible parties exist, costs are estimated and recordedonly for PSCo’s expected share of the cost. Any future costs of restoring siteswhere operation may extend indefinitely are treated as a capitalized cost ofplant retirement. The depreciation expense levels recoverable in rates includea provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates areclassified as a regulatory liability.

***Legal Costs*** — Legal costs are notaccrued, but expensed as incurred.

***Income Taxes*****— Xcel Energy and its utility subsidiaries, including PSCo,file consolidated federal and combined and separate state income tax returns.Income taxes for consolidated or combined subsidiaries are allocated to thesubsidiaries based on separate company computations of taxable income orloss.  The holding company also allocatesits own net income tax benefits to its direct subsidiaries based on thepositive tax liability of each company in the consolidated federal or combinedstate returns. PSCo defers income taxes for all temporary differences betweenthe book and tax bases of assets and liabilities. The tax rates used are thosethat are scheduled to be in effect when the temporary differences are expectedto turn around, or reverse.

Investment tax creditsare deferred and their benefits amortized over the estimated lives of therelated property. Utility rate regulation also has created certain regulatoryassets and liabilities related to income taxes, which are summarized in Note 13to the Consolidated Financial Statements. For more information on income taxes,see Note 6 to the Consolidated Financial Statements.

***Use of Estimates*****— In recording transactions and balancesresulting from business operations, PSCo uses estimates based on the bestinformation available. Estimates are used for such items as plant depreciablelives, asset retirement obligations, decommissioning, tax provisions,uncollectible amounts, environmental costs, unbilled revenues, jurisdictionalfuel and energy cost allocations and actuarially determined benefit costs. Therecorded estimates are revised when better information is obtained or actualamounts are determinable. Those revisions can affect operating results. Eachyear the depreciable lives of certain plant assets are reviewed and revised, ifappropriate.

***Cash and Cash Equivalents*****— PSCo considers investments in certaininstruments, including commercial paper and money market funds, with aremaining maturity of three months or less at the time of purchase to be cashequivalents.

***Inventory*****— All inventories are recorded at average cost.

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

·       certain costs, which wouldotherwise be charged to expense, are deferred as regulatory assets based on theexpected ability to recover them in future rates; and

·       certain credits, whichwould otherwise be reflected as income, are deferred as regulatory liabilitiesbased on the expectation they will be returned to customers in future rates.

34

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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, 2006and 2005 were $11.4 million and $13.5 million, respectively.

***Accounts Receivableand Allowance for Uncollectibles*—**Accounts receivableare stated at the actual billed amount net of the allowance foruncollectibles.  PSCo establishes anallowance for uncollectibles based on a reserve policy that reflects itsexpected exposure to the credit risk of customers.

***Emission Allowances*—**Emissionallowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlementreceived at no cost from the Federal EPA. PSCo follows the inventory model for all allowances.  The sales of allowances are reported in theOperating Activities section of the Consolidated Statements of Cash Flows.  The net margin on sales of emissionallowances is included in Operating Revenues as it is integral to theproduction process of energy and our revenue optimization strategy for ourutility operations.

***FASB Interpretation No. 48 (FIN 48)***— In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty inIncome Taxes — an interpretation of FASB Statement No. 109.” FIN 48prescribes how a company should recognize, measure, present and discloseuncertain tax positions that the company has taken or expects to take in itsincome tax returns. FIN 48 requires that only income tax benefits that meet the“more likely than not” recognition threshold be recognized or continue to berecognized on its effective date. Initial derecognition amounts would bereported as a cumulative effect of a change in accounting principle. Followingimplementation, the ongoing recognition of changes in the measurement ofuncertain tax positions could be reflected as a component of income taxexpense.

FIN 48is effective for fiscal years beginning after Dec. 15, 2006. PSCo has substantiallycompleted its analysis and does not expect the cumulative effect of theadoption to be material.

***Fair Value Measurements (SFASNo. 157) —*** In September 2006, the FASB issuedSFAS No. 157, which provides a single definition of fair value, togetherwith a framework for measuring it, and requires additional disclosure about theuse of fair value to measure assets and liabilities. SFAS No. 157 alsoemphasizes that fair value is a market-based measurement, and sets out a fairvalue hierarchy with the highest priority being quoted prices in activemarkets.  Fair value measurements aredisclosed by level within that hierarchy. SFAS No. 157 is effective forfinancial statements issued for fiscal years beginning after Nov. 15,2007. PSCo is evaluating the impact of SFAS No. 157 on its financialcondition and results of operations and does not expect the impact ofimplementation to be material.

**2.Short-Term Borrowings**

***Commercial Paper*—**At Dec. 31, 2006and 2005, PSCo had commercial paper outstanding of approximately $372.5 millionand $335.6 million, respectively.  Theweighted average interest rates at Dec. 31, 2006 and 2005 were 5.43 percent and4.48 percent, respectively.

***Money Pool***- Xcel Energy hasestablished a utility money pool arrangement with the utility subsidiaries andreceived required state regulatory approvals. Approval was also granted by the FERC in a July 18, 2006 order.  The utility money pool allows for short-termloans between the utility subsidiaries and from the holding company to theutility subsidiaries at market-based interest rates. The utility money poolarrangement does not allow loans from the utility subsidiaries to the holdingcompany.  PSCo has approval to borrow upto $250 million under the arrangement. PSCo had no borrowings or loans outstanding under the arrangement atDec. 31, 2006.

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

Effective Oct. 14, 2005,PSCo discharged its Indenture, in accordance with its terms, dated as of Dec.1, 1939, as supplemented (1939 Indenture). As a result, PSCo’s Indenture, dated as of Oct. 1, 1993, as supplemented(1993 Indenture), became the first lien on PSCo’s electric properties subjectto certain permitted liens as provided in the 1993 Indenture.  PSCo’s outstanding first collateral trustbonds issued under the 1993 Indenture are no longer be secured by bonds issuedunder the 1939 Indenture and are first mortgage bonds entitled to the benefitof the lien on PSCo’s electric properties under the 1993 Indenture and havebeen renamed “first mortgage bonds” to reflect this status.

35

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***Credit Facilities*—**At Dec. 31, 2006,PSCo had the following committed credit facility in effect, in millions of dollars:

| Credit Facility | ** ** | **Credit Facility  Borrowings** | ** ** | **Available*** | ** ** | **Term** | ** ** | **Maturity** | ** ** |
|----------------------|------------|--------------------------------------|------------|----------------|------------|----------|------------|--------------|------------|
| $700                 |       | $                                    | —     |           | $          | 321.5    |       | Five  year   |       | December 2011 |   |
|                      |            |                                      |            |                |            |          |            |              |            |  |  |

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

The line of creditprovides short-term financing in the form of notes payable to banks, letters ofcredit and back-up support for commercial paper borrowings.  PSCo has the right to request an extension ofthe final maturity date by one year.  Thematurity extension is subject to majority bank group approval.  The credit facility has one financialcovenant requiring that PSCo’s debt to total capitalization ratio be less thanor equal to 65 percent with which PSCo was in compliance at Dec. 31, 2006.  The interest rate is based on either theagent bank’s prime rate or the applicable LIBOR, plus a borrowing margin asdetermined by PSCo’s senior unsecured credit ratings from Moody, Standard &Poor and Fitch.

As of Dec. 31,2006, PSCo had no direct borrowings on this line of credit; however, thiscredit facility was used to provide back-up support for PSCo commercial paperand letters of credit.  Also, $6.0million of letters of credit were outstanding at Dec. 31, 2006, as discussed inNote 10 to the Consolidated Financial Statements, of which approximately $6.0million were outstanding under the above credit facility.

Maturities of long-termdebt are:

| (Millions of Dollars) | ** ** | ** ** | ** ** |
|---------------------------------|------------|------------|------------|
| 2007                            |       | $          | 101.4      |   |
| 2008                            |       | $          | 301.4      |   |
| 2009                            |       | $          | 201.5      |   |
| 2010                            |       | $          | 1.6        |   |
| 2011                            |       | $          | 1.6        |   |

 

**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. JointPlant Ownership**

Following are theinvestments by PSCo in jointly owned plants and the related ownershippercentages as of Dec. 31, 2006:
| **(Thousands of Dollars)**                      | ** ** | **Plant in  Service** | ** ** | **Accumulated  Depreciation** | ** ** | **Construction  Work in  Progress** | ** ** | **Ownership%** | ** ** |
|-----------------------------------------------------------|------------|----------------------------|------------|-------------------------------|------------|------------------------------------------|------------|----------------|------------|
| Hayden Unit 1                                             |       | $                          | 87,051     |                          | $          | 45,840                                   |       | $              | 371        |   | 75.5 |   |
| Hayden Unit 2                                             |       | 81,467                     |       | 47,021                        |       | 544                                      |       | 37.4           |       |
| Hayden Common  Facilities                                 |       | 28,270                     |       | 6,343                         |       | —                                   |       | 53.1           |       |
| Craig Units 1  and 2                                      |       | 52,872                     |       | 27,061                        |       | 316                                      |       | 9.7            |       |
| Craig Common  Facilities, Units 1, 2 and 3                |       | 31,888                     |       | 10,158                        |       | 323                                      |       | 6.5-9.7        |       |
| Comanche Unit 3                                           |       | —                     |       | —                        |       | 215,557                                  |       | 66.7           |       |
| Transmission and  other facilities, including substations |       | 139,725                    |       | 49,846                        |       | 488                                      |       | 11.6-68.1      |       |
| Total                                                     |       | $                          | 421,273    |                          | $          | 186,269                                  |       | $              | 217,599    |   |   |   |

 

PSCo’s currentoperational assets include approximately 320 MWs of jointly owned generatingcapacity.  PSCo’s share of operatingexpenses and construction expenditures are included in the applicable utilityaccounts.  PSCo began major constructionon a new jointly owned 750 MW coal-fired unit in Pueblo, Colo. in January 2006.  Major construction on the new unit, Comanche3, is expected to be completed in the fall of 2009.  PSCo is the operating agent under the jointownership agreement.  Each of therespective owners is responsible for funding its portion of the constructioncosts.  For Comanche unit 3, the ownershippercentage for Xcel Energy decreased in May 2006 from 74.7 percent to 66.7percent for the project life-to-date and going forward.

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**6.Income Taxes**

Total income tax expensefrom operations differs from the amount computed by applying the statutory federalincome tax rate to income before income tax expense. The following is a tablereconciling such differences for the years ending Dec. 31:

|                                                        | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal  statutory rate                                |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  (decreases) in tax from:                    |       |     |       |     |       |     |       |
| State income taxes, net of federal income tax  benefit |       | 4.3      |       | 2.3      |       | 3.4      |       |
| Regulatory differences — utility plant items      |       | 0.2      |       | 0.3      |       | 1.5      |       |
| Life insurance policies                                |       | (10.6    | )          | (10.8    | )          | (9.4     | )          |
| Tax credits recognized                                 |       | (2.0     | )          | (2.5     | )          | (2.1     | )          |
| Resolution of income tax audits                        |       | (1.1     | )          | 0.5      |       | (4.9     | )          |
| Other — net                                       |       | (0.5     | )          | 0.1      |       | 1.5      |       |
| Effective income tax  rate                             |       | 25.3     | %          | 24.9     | %          | 25.0     | %          |

 

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

| (Thousands of Dollars) | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current federal  tax expense     |       | $        | (2,691     | )        | $          | (32,833  | )          | $ | (2,866 | ) |
| Current state  tax expense       |       | 12,301   |       | (4,411   | )          | 2,229    |       |
| Current tax  credits             |       | —   |       | —   |       | (2,000   | )          |
| Deferred federal  tax expense    |       | 71,756   |       | 102,132  |       | 67,700   |       |
| Deferred state  tax expense      |       | 6,807    |       | 12,512   |       | 11,793   |       |
| Deferred tax  credits            |       | (2,523   | )          | (3,189   | )          | —   |       |
| Deferred  investment tax credits |       | (3,949   | )          | (3,971   | )          | (4,000   | )          |
| Total income tax  expense        |       | $        | 81,701     |     | $          | 70,240   |       | $ | 72,856 |   |

 

The components ofdeferred income tax at Dec. 31 were:

| (Thousands of Dollars)                                                                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred tax  expense excluding items below                                                             |       | $        | 149,056    |     | $          | 89,333 |   |
| Amortization and  adjustments to deferred income taxes on income tax regulatory assets and  liabilities |       | (808     | )          | 4,801    |       |
| Tax expense  (benefit) allocated to other comprehensive income and other                                |       | (72,208  | )          | 17,321   |       |
| Deferred tax  expense                                                                                   |       | $        | 76,040     |     | $          | 111,455 |   |

 

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

| (Thousands of Dollars)                   | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|----------------------------------------------------|------------|------------|------------|------------|------------|
| Deferred tax  liabilities:                         |       |       |       |       |       |
| Differences between book and tax basis of property |       | $          | 995,760    |       | $          | 912,876 |   |
| Deferred costs                                     |       | 57,518     |       | 84,685     |       |
| Regulatory assets                                  |       | 51,723     |       | 47,937     |       |
| Employee benefits                                  |       | 20,907     |       | 20,356     |       |
| Other comprehensive income                         |       | 7,669      |       | —     |       |
| Other                                              |       | 4,088      |       | 12,143     |       |
| Total deferred tax liabilities                     |       | $          | 1,137,665  |       | $          | 1,077,997 |   |
|                                               |       |       |       |       |       |
| **Deferred tax assets:**                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Unbilled revenue                                   |       | $          | 71,986     |       | $          | 90,379 |   |
| Other comprehensive income                         |       | —     |       | 64,538     |       |
| Net operating loss carryforward                    |       | 59,362     |       | 66,917     |       |
| Deferred investment tax credits                    |       | 22,242     |       | 23,680     |       |
| Regulatory liabilities                             |       | 13,626     |       | 13,479     |       |
| Other                                              |       | 29,213     |       | 26,824     |       |
| Total deferred tax assets                          |       | $          | 196,429    |       | $          | 285,817 |   |
| Net deferred tax  liability                        |       | $          | 941,236    |       | $          | 792,180 |   |

 

37

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**7.Benefit Plans and Other Postretirement Benefits**

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

Xcel Energy offersvarious benefit plans to its benefit employees, including those of PSCo.Approximately 56 percent of benefit employees are represented by several locallabor unions under several collective-bargaining agreements. At Dec. 31, 2006,PSCo had 2,165 bargaining employees covered under a collective-bargainingagreement, which expires in May 2009.

**Employers’ Accounting for DefinedBenefit Pension and Other Postretirement Plans—an amendment of FASB StatementsNo. 87, 88, 106, and 132(R) (SFAS No. 158)** — In September2006, the FASB issued SFAS No. 158, which requires companies to fully recognizethe funded status of each pension and other postretirement benefit plan as aliability or asset on their balance sheets with all unrecognized amounts to berecorded in other comprehensive income. The following table shows the impact of the implementation on theconsolidated statement of financial position. PSCo applied regulatory accounting treatment, which allowed recognitionof this item as a regulatory asset rather than as a charge to accumulated othercomprehensive income, as future costs are expected to be included inrates.  The table reflects the deferralof these amounts as regulatory assets. This table also includes noncontributory, defined benefit supplementalretirement income plans. 
| **Balance Sheet Line**                | ** ** | **Pre-SFAS   No. 158** | ** ** | **SFAS No. 158   Adjustment** | ** ** | **SFAS No. 71   Adjustment** | ** ** | **After SFAS   No. 158** | ** ** |
|-------------------------------------------------|------------|----------------------------------|------------|----------------------------------------------|------------|---------------------------------------------|------------|-----------------------------------------|------------|
|                                            |       |                             |       |                                         |       |                                        |       |                                    |       |
| Regulatory  assets                              |       | $                                | 226,013    |                                         | $          | —                                      |       | $                                       | 363,003    |   | $ | 589,016 |   |
| Other (long-term  assets)                       |       | 48,417                           |       | (2,633                                       | )          | —                                      |       | 45,784                                  |       |
| Prepayments and  other (current deferred taxes) |       | 14,339                           |       | 315                                          |       | —                                      |       | 14,654                                  |       |
| Total Assets                                    |       | $                                | 288,769    |                                         | $          | (2,318                                      | )          | $                                       | 363,003    |   | $ | 649,454 |   |
|                                            |       |                             |       |                                         |       |                                        |       |                                    |       |
| Other (current  liabilities)                    |       | $                                | 73,549     |                                         | $          | 832                                         |       | $                                       | —     |   | $ | 74,381 |   |
| Pension and  employee benefit obligations       |       | 84,547                           |       | 216,730                                      |       | —                                      |       | 301,277                                 |       |
| Deferred income  taxes                          |       | 949,717                          |       | (82,939                                      | )          | 137,249                                     |       | 1,004,027                               |       |
| Total  Liabilities                              |       | $                                | 1,107,813  |                                         | $          | 134,623                                     |       | $                                       | 137,249    |   | $ | 1,379,685 |   |
|                                            |       |                             |       |                                         |       |                                        |       |                                    |       |
| AOCI-net of tax                                 |       | $                                | (76,199    | )                                            | $          | (136,941                                    | )          | $                                       | 225,754    |   | $ | 12,614 |   |
| Total Equity                                    |       | $                                | (76,199    | )                                            | $          | (136,941                                    | )          | $                                       | 225,754    |   | $ | 12,614 |   |

 

**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 isto fully 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 assetsprincipally consist of the common stock of public companies, corporate bondsand U.S. government securities. The target range for our pension assetallocation is 60 percent in equity investments, 20 percent in fixed incomeinvestments and 20 percent in nontraditional investments, such as real estate,private equity and a diversified commodities index.

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

|                             | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|
| Equity  securities          |       | 63       | %          | 65       | %          |
| Debt securities             |       | 22       |       | 20       |       |
| Real estate                 |       | 4        |       | 4        |       |
| Cash                        |       | 2        |       | 1        |       |
| Nontraditional  investments |       | 9        |       | 10       |       |
|                        |       | 100      | %          | 100      | %          |

 

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 11.3 percent, which is greater than the current assumptionlevel. The pension cost determination assumes 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. A higher weighting in equity investments can increase the volatility inthe return levels achieved by pension assets in any year. Investment returns in2006, 2005 and 2004 exceeded the assumed level of 8.75, 8.75 and 9.0 percent,respectively.  Xcel Energy continuallyreviews its pension assumptions.  In2007, Xcel Energy will continue to use an investment-return assumption of 8.75percent.

38

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***Benefit Obligations***— A comparison ofthe actuarially computed pension benefit obligation and plan assets, on acombined basis, is presented in the following table:

 

| (Thousands of Dollars)                                                                | ** ** | **2006**                | ** ** | **2005**                | ** ** |
|-------------------------------------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
| **Accumulated  Benefit Obligation at Dec. 31**                                                  |       | $                       | 2,486,370  |                    | $          | 2,642,177 |   |
|                                                                                            |       |                    |       |                    |       |
| **Change  in Projected Benefit Obligation**                                                     |       |                    |       |                    |       |
| Obligation at  Jan. 1                                                                           |       | $                       | 2,796,780  |                    | $          | 2,732,263 |   |
| Service cost                                                                                    |       | 61,627                  |       | 60,461                  |       |
| Interest cost                                                                                   |       | 155,413                 |       | 160,985                 |       |
| Plan amendments                                                                                 |       | (16,569                 | )          | 300                     |       |
| Actuarial (gain)  loss                                                                          |       | (82,339                 | )          | 85,558                  |       |
| Benefit payments                                                                                |       | (248,357                | )          | (242,787                | )          |
| Obligation at  Dec. 31                                                                          |       | $                       | 2,666,555  |                    | $          | 2,796,780 |   |
|                                                                                            |       |                    |       |                    |       |
| **Change  in Fair Value of Plan Assets**                                                        |       |                    |       |                    |       |
| Fair value of  plan assets at Jan. 1                                                            |       | $                       | 3,093,536  |                    | $          | 3,062,016 |   |
| Actual return on  plan assets                                                                   |       | 306,196                 |       | 254,307                 |       |
| Employer  contributions                                                                         |       | 32,000                  |       | 20,000                  |       |
| Benefit payments                                                                                |       | (248,357                | )          | (242,787                | )          |
| Fair value of  plan assets at Dec. 31                                                           |       | $                       | 3,183,375  |                    | $          | 3,093,536 |   |
|                                                                                            |       |                    |       |                    |       |
| **Funded  Status of Plans at Dec. 31**                                                          |       |                    |       |                    |       |
| Funded status                                                                                   |       | $                       | 516,820    |                    | $          | 296,756 |   |
| Noncurrent  assets                                                                              |       | 586,713                 |       | 685,028                 |       |
| Noncurrent  liabilities                                                                         |       | (69,893                 | )          | (90,595                 | )          |
| Net pension  amounts recognized on Consolidate Balance Sheets                                   |       | $                       | 516,820    |                    | $          | 594,433 |   |
|                                                                                            |       |                    |       |                    |       |
| **PSCo  Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:**                |       |                    |       |                    |       |
| Net loss                                                                                        |       | $                       | 164,970    |                    | $          | 210,085 |   |
| Prior service  cost                                                                             |       | 24,387                  |       | 26,057                  |       |
| Total                                                                                           |       | $                       | 189,357    |                    | $          | 236,142 |   |
|                                                                                            |       |                    |       |                    |       |
| **SFAS  No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in  Rates:** |       |                    |       |                    |       |
| Regulatory  assets                                                                              |       | $                       | 189,357    |                    | N/A        |   |
| Total                                                                                           |       | $                       | 189,357    |                    | N/A        |   |
|                                                                                            |       |                    |       |                    |       |
| PSCo accrued  benefit liability recorded                                                        |       | $                       | (68,513    | )                       | $          | (88,414 | ) |
|                                                                                            |       |                    |       |                    |       |
| **Measurement  Date**                                                                           |       | Dec. 31, 2006 |       | Dec. 31, 2005 |       |
| ** **                                                                                      |       |                    |       |                    |       |
| **Significant  Assumptions Used to Measure Benefit Obligations**                                |       |                    |       |                    |       |
| Discount rate  for year-end valuation                                                           |       | 6.00                    | %          | 5.75                    | %          |
| Expected average  long-term increase in compensation level                                      |       | 4.00                    | %          | 3.50                    | %          |

 

During 2002, PSCo’spension plans became underfunded, and at Dec. 31, 2006, had projectedbenefit obligations of $728.1 million, which exceeded plan assets of $658.2million.  At Dec. 31, 2005, theprojected benefit obligations of $739.5 million, exceeded plan assets of $609.8million. All other Xcel Energy plans in the aggregate had plan assets of $2.5billion and projected benefit obligations of $1.9 billion on Dec. 31,2006.

39

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***Cash Flows***— Cash funding requirementscan be impacted by changes to actuarial assumptions, actual asset levels andother calculations prescribed by the funding requirements of income tax andother pension-related regulations. These regulations did not require cashfunding in the years 2004 through 2006 for Xcel Energy’s pension plans, and arenot expected to require cash funding in 2007. PSCo elected to make voluntarycontributions to its pension plan for bargaining employees of $29 million, $15million and $10 million in 2006, 2005 and 2004, respectively.  During 2007, Xcel Energy expects tovoluntarily contribute approximately $20 million to the PSCo pension plan forbargaining employees.

***Plan Changes*—** The Pension ProtectionAct of 2006 (PPA) was reflected effective December 31, 2006.  PPA requires a change in the conversion basisfor lump-sum payments, three-year vesting for plans with account balance orpension equity benefits, as well as the repeal of the Economic Growth and Tax Relief Reconciliation Act of 2001 sunset provisions.  These changes are reflected as a planamendment for purposes of SFAS No. 87.

***Benefit Costs***—******The components ofnet periodic pension cost (credit) are:

| (Thousands of Dollars)                           | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                               |       | $        | 61,627     |     | $          | 60,461   |       | $ | 58,150 |   |
| Interest cost                                              |       | 155,413  |       | 160,985  |       | 165,361  |       |
| Expected return  on plan assets                            |       | (268,065 | )          | (280,064 | )          | (302,958 | )          |
| Settlement gain                                            |       | —   |       | —   |       | (926     | )          |
| Amortization of  transition asset                          |       | —   |       | —   |       | (7       | )          |
| Amortization of  prior service cost                        |       | 29,696   |       | 30,035   |       | 30,009   |       |
| Amortization of  net (gain) loss                           |       | 17,353   |       | 6,819    |       | (15,207  | )          |
| Net periodic  pension credit under SFAS No. 87             |       | $        | (3,976     | )        | $          | (21,764  | )          | $ | (65,578 | ) |
|                                                       |       |     |       |     |       |     |       |
| **PSCo**                                                   |       |     |       |     |       |     |       |
| Net periodic  pension cost (credit)                        |       | $        | 18,666     |     | $          | 14,252   |       | $ | 7,141 |   |
|                                                       |       |     |       |     |       |     |       |
| **Significant  Assumptions Used to Measure Costs**         |       |     |       |     |       |     |       |
| Discount rate                                              |       | 5.75     | %          | 6.00     | %          | 6.25     | %          |
| Expected average  long-term increase in compensation level |       | 3.50     | %          | 3.50     | %          | 3.50     | %          |
| Expected average  long-term rate of return on assets       |       | 8.75     | %          | 8.75     | %          | 9.00     | %          |

 

Pension costs include anexpected return impact for the current year that may differ from actualinvestment performance in the plan. The return assumption used for 2007 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 alsomaintains noncontributory, defined benefit supplemental retirement income plansfor certain qualifying executive personnel. Benefits for these unfunded plansare paid out of Xcel Energy’s operating cash flows.

**DefinedContribution Plans**

Xcel Energy maintains401(k) and other defined contribution plans that cover substantially all employees.The contributions for PSCo  wereapproximately $6.2 million in 2006, $6.2 million in 2005 and $7.2 million in2004.

**PostretirementHealth Care Benefits**

Xcel Energy has acontributory health and welfare benefit plan that provides health care and deathbenefits to most Xcel Energy retirees. Employees of the former NCE who retiredin 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 the1993 adoption of SFAS No. 106 — “Employers’ Accounting for PostretirementBenefits Other Than Pensions,” Xcel Energy elected to amortize the unrecognizedaccumulated postretirement benefit obligation (APBO) on a straight-line basisover 20 years.

Regulatory agencies fornearly all of Xcel Energy’s retail and wholesale utility customers have allowedrate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned tofull accrual accounting for SFAS No. 106 costs between 1993 and 1997,consistent with the accounting requirements for rate-regulated enterprises. TheColorado jurisdictional SFAS

40

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No. 106 costs deferredduring the transition period are being amortized to expense on a straight-linebasis over the 15-year period from 1998 to 2012.

***Plan Assets***— Certain state agenciesthat regulate Xcel Energy’s utility subsidiaries also have issued guidelinesrelated to the funding of SFAS No. 106 costs. PSCo is required to fund SFAS No.106 costs in irrevocable external trusts that are dedicated to the payment ofthese postretirement benefits. In 2004, the investment strategy for the unionasset fund was changed to increase the investment mix to equity funds. Also, a portionof the assets contributed on behalf of non-bargaining retirees has been fundedinto a sub-account of the Xcel Energy pension plans. These assets are investedin a manner consistent with the investment strategy for the pension plan.

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

|                                           | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Equity and  equity mutual fund securities |       | 67       | %          | 61       | %          |
| Fixed  income/debt securities             |       | 21       |       | 17       |       |
| Cash equivalents                          |       | 11       |       | 21       |       |
| Nontraditional  Investments               |       | 1        |       | 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.

***Benefit Obligations***— A comparison ofthe actuarially computed benefit obligation and plan assets for Xcel Energypostretirement health care plans that benefit employees of its utilitysubsidiaries is presented in the following table:

| (Thousands of Dollars)                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|
| **Change  in Benefit Obligation**                      |       |     |       |     |       |
| Obligation at  Jan. 1                                  |       | $        | 938,172    |     | $          | 929,125 |   |
| Service cost                                           |       | 6,633    |       | 6,684    |       |
| Interest cost                                          |       | 52,939   |       | 55,060   |       |
| Medicare subsidy  reimbursements                       |       | 3,561    |       | —   |       |
| Plan amendments                                        |       | (945     | )          | —   |       |
| Plan  participants’ contributions                 |       | 11,870   |       | 12,008   |       |
| Actuarial gain                                         |       | (27,511  | )          | (3,175   | )          |
| Benefit payments                                       |       | (66,026  | )          | (61,530  | )          |
| Obligation at  Dec. 31                                 |       | $        | 918,693    |     | $          | 938,172 |   |
|                                                   |       |     |       |     |       |
| **Change  in Fair Value of Plan Assets**               |       |     |       |     |       |
| Fair value of  plan assets at Jan. 1                   |       | $        | 351,863    |     | $          | 318,667 |   |
| Actual return on  plan assets                          |       | 41,409   |       | 14,507   |       |
| Plan  participants’ contributions                 |       | 11,870   |       | 12,008   |       |
| Employer  contributions                                |       | 67,188   |       | 68,211   |       |
| Benefit payments                                       |       | (66,025  | )          | (61,530  | )          |
| Fair value of  plan assets at Dec. 31                  |       | $        | 406,305    |     | $          | 351,863 |   |
|                                                   |       |     |       |     |       |
| **Funded  Status at Dec. 31**                          |       |     |       |     |       |
| Funded status                                          |       | $        | (512,388   | )        | $          | (586,309 | ) |
| Current  liabilities                                   |       | (2,211   | )          | —   |       |
| Noncurrent  assets                                     |       | —   |       | 15,736   |       |
| Noncurrent  liabilities                                |       | (510,177 | )          | (150,014 | )          |
| Net amounts recognized  on Consolidated Balance Sheets |       | $        | (512,388   | )        | $          | (134,278 | ) |

 

41

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| **PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:**                         |   |                    |    |                    |   |
|-------------------------------------------------------------------------------------------------|--------|-------------------------|---------|-------------------------|--------|
| Net loss                                                                                        |   | $                       | 106,450 |                    | $      | 164,158 |   |
| Prior service  cost (credit)                                                                    |   | (2,613                  | )       | (3,041                  | )      |
| Transition  obligation                                                                          |   | 66,809                  |    | 77,813                  |   |
| Total                                                                                           |   | $                       | 170,646 |                    | $      | 238,930 |   |
|                                                                                            |   |                    |    |                    |   |
| **SFAS  No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in  Rates:** |   |                    |    |                    |   |
| Regulatory  assets                                                                              |   | $                       | 170,646 |                    | N/A    |   |
| Total                                                                                           |   | $                       | 170,646 |                    | N/A    |   |
|                                                                                            |   |                    |    |                    |   |
| PSCo accrued  benefit liability recorded                                                        |   | $                       | 207,992 |                    | $      | 39,503 |   |
|                                                                                            |   |                    |    |                    |   |
| **Measurement  Date**                                                                           |   | Dec. 31, 2006 |    | Dec. 31, 2005 |   |
|                                                                                            |   |                    |    |                    |   |
| **Significant  Assumptions Used to Measure Benefit Obligations**                                |   |                    |    |                    |   |
| Discount rate for  year-end valuation                                                           |   | 6.00                    | %       | 5.75                    | %      |

 

Effective Dec. 31, 2004,Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0percent and lowered the ultimate trend assumption from 5.5 percent to 5.0percent.  The period until the ultimaterate is reached was also increased from two years to six years.  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, 2006                         |       | $59.7      |       |
| 1-percent decrease in  APBO components at Dec. 31, 2006                         |       | (49.9      | )          |
| 1-percent increase in  service and interest components of the net periodic cost |       | 4.9        |       |
| 1-percent decrease in  service and interest components of the net periodic cost |       | (4.0       | )          |

 

***Plan Changes*** - The employer subsidyfor retiree medical coverage was eliminated for former New Century Energies,Inc. non-bargaining employees who retire after July 1, 2003. 

***Cash Flows***— The postretirement healthcare plans have no funding requirements under income tax and otherretirement-related regulations other than fulfilling benefit paymentobligations, 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 $61 million during 2007.

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

| (Thousands of Dollars)                                      | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service cost                                                          |       | $        | 6,633      |     | $          | 6,684    |       | $ | 6,100 |   |
| Interest cost                                                         |       | 52,939   |       | 55,060   |       | 52,604   |       |
| Expected return  on plan assets                                       |       | (26,757  | )          | (25,700  | )          | (23,066  | )          |
| Amortization of  transition obligation                                |       | 14,444   |       | 14,578   |       | 14,578   |       |
| Amortization of  prior service credit                                 |       | (2,178   | )          | (2,178   | )          | (2,179   | )          |
| Amortization of  net loss                                             |       | 24,797   |       | 26,246   |       | 21,651   |       |
| Net periodic  postretirement benefit cost (credit) under SFAS No. 106 |       | $        | 69,878     |     | $          | 74,690   |       | $ | 69,688 |   |

 

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| **PSCo**                                                                 |   |   |   |     |   |     |   |
|--------------------------------------------------------------------------|--------|--------|--------|----------|--------|----------|--------|
| Net periodic  postretirement benefit cost recognized — SFAS No. 106 |   | 39,976 |   | 43,841   |   | 42,248   |   |
| Additional cost  recognized due to effects of regulation                 |   | 3,891  |   | 3,891    |   | 3,891    |   |
| Net cost recognized for financial reporting                              |   | $      | 43,867 |     | $      | 47,732   |   | $ | 46,139 |   |
|                                                                     |   |   |   |     |   |     |   |
| **Significant  assumptions used to measure costs (income)**              |   |   |   |     |   |     |   |
| Discount rate                                                            |   | 5.75   | %      | 6.00     | %      | 6.25     | %      |
| Expected average  long-term rate of return on assets (before tax)        |   | 7.5    | %      | 5.5%-8.5 | %      | 5.5%-8.5 | %      |
|                                                                          |        |        |        |          |        |          |        |  |  |  |

 

# **ProjectedBenefit Payments**

Thefollowing table lists Xcel Energy’s projected benefit payments for the pensionand 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** | ** ** |
|--------------------------------------|------------|---------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| 2007                                 |       | $                                                 | 217,236    |                                                                              | $          | 65,355                                                 |       | $                                                                               | 5,358      |   | $ | 59,997 |   |
| 2008                                 |       | 215,815                                           |       | 67,110                                                                            |       | 5,755                                                  |       | 61,355                                                                          |       |
| 2009                                 |       | 220,843                                           |       | 68,911                                                                            |       | 6,115                                                  |       | 62,796                                                                          |       |
| 2010                                 |       | 227,528                                           |       | 70,457                                                                            |       | 6,430                                                  |       | 64,027                                                                          |       |
| 2011                                 |       | 225,446                                           |       | 71,924                                                                            |       | 6,665                                                  |       | 65,259                                                                          |       |
| 2012-2016                            |       | 1,195,629                                         |       | 368,206                                                                           |       | 36,592                                                 |       | 331,614                                                                         |       |
|                                      |            |                                                   |            |                                                                                   |            |                                                        |            |                                                                                 |            |  |  |  |  |

 

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**8.Detail of Interest and Other Income (Expense) - Net**

Interest and otherincome, net of nonoperating expenses, for the years ended Dec. 31 consists ofthe following:
| **(Thousands of Dollars)**                                                              | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
|                                                                                              |       |     |       |     |       |     |       |
| Interest income                                                                                   |       | $        | 4,462      |     | $          | 2,801    |       | $ | 9,194 |   |
| Other nonoperating  income                                                                        |       | 2,581    |       | 3,621    |       | 8,346    |       |
| Interest expense on  corporate-owned life insurance and other employee-related insurance policies |       | (20,404  | )          | (18,273  | )          | (17,075  | )          |
| Other nonoperating  expense                                                                       |       | (862     | )          | (33      | )          | (441     | )          |
| Total interest and other  (expense) income — net                                             |       | $        | (14,223    | )        | $          | (11,884  | )          | $ | 24 |   |

 

**9.Derivative Instruments**

In thenormal course of business, PSCo is exposed to a variety of market risks.  Market risk is the potential loss that mayoccur as a result of changes in the market or fair value of a particularinstrument or commodity.  PSCo utilizes,in accordance with approved risk management policies, a variety of derivativeinstruments to mitigate market risk and to enhance its operations.  The use of these derivative instruments isdiscussed in further detail below.

***Utility Commodity Price Risk —***PSCo is exposed to commodity price risk in its electric and natural gasoperations.  Commodity price risk ismanaged by entering into both long- and short-term physical purchase and salescontracts for electric capacity, energy and other energy-related products, andfor various fuels used in the generation of electricity and natural gas utilityoperations.  Commodity risk also ismanaged through the use of financial derivative instruments.  PSCo utilizes these derivative instruments toreduce the volatility in the cost of commodities acquired on behalf of itsretail customers even though regulatory jurisdiction may provide for adollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is doneconsistently with the local jurisdictional cost-recovery mechanism.  PSCo’s risk management policy allows it tomanage market price risk within each rate-regulated operation to the extentsuch exposure exists.

***Short-Term Wholesale and Commodity TradingRisk —*** PSCo conducts various short-term wholesale andcommodity trading activities, including the purchase and sale of electriccapacity, energy and other energy-related instruments.  PSCo’s risk management policy allowsmanagement to conduct the marketing activity within guidelines and limitationsas approved by our risk management committee, which is made up of managementpersonnel not directly involved in the activities governed by this policy.

***Interest Rate Risk —***PSCois subject to the risk of fluctuating interest rates in the normal course ofbusiness.  PSCo’s risk management policyallows interest rate risk to be managed through the use of fixed rate debt,floating rate debt and interest rate derivatives such as swaps, caps, collarsand put or call options.

# **Types ofand Accounting for Derivative Instruments**

PSCouses derivative instruments in connection with its utility commodity price,interest rate, short-term wholesale and commodity trading activities, includingforward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases andnormal sales exception, as defined by SFAS No. 133, are recorded at fair value.The classification of the fair value for these derivative instruments isdependent on the designation of a qualifying hedging relationship.  The adjustment to fair value of derivativeinstruments not designated in a qualifying hedging relationship is reflected incurrent earnings or as a regulatory balance. This classification is dependent on the applicability of specificregulation.  This includes certaininstruments used to mitigate market risk for PSCo and all instruments relatedto the commodity trading operations.  Thedesignation of a cash flow hedge permits the classification of fair value to berecorded within Other Comprehensive Income, to the extent effective.  The designation of a fair value hedge permitsa derivative instrument’s gains or losses to offset the related results of thehedged item in the Consolidated Statements of Income.

SFASNo. 133 requires that the hedging relationship be highly effective and that acompany formally designate a hedging relationship to apply hedgeaccounting.  PSCo formally documentshedging relationships, including, among other factors, the identification ofthe hedging instrument and the hedged transaction, as well as the riskmanagement objectives and strategies for undertaking the hedgedtransaction.  PSCo also formally assesses,both at inception 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.

Gainsor losses on hedging transactions for the sales of energy or energy-relatedproducts are primarily recorded as a component of revenue; hedging transactionsfor fuel used in energy generation are recorded as a component of fuel costs;hedging transactions for natural gas purchased for resale are recorded as acomponent of natural gas costs; and interest rate 

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hedgingtransactions 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.

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

# **Cash FlowHedges**

Theeffective portion of the change in the fair value of a derivative instrumentqualifying as a cash flow hedge is recorded as a component of OtherComprehensive Income or deferred as a regulatory asset or liability, andreclassified 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******—***PSCoenters into derivative instruments to manage variability of future cash flowsfrom changes in commodity prices.  Thesederivative instruments are designated as cash flow hedges for accountingpurposes.  At Dec. 31, 2006, PSCo hadvarious commodity-related contracts classified as cash flow hedges extendingthrough December 2009.  The fair value ofthese cash flow hedges is recorded in either Other Comprehensive Income ordeferred as a regulatory asset or liability. This classification is based onthe regulatory recovery mechanisms in place.  Amounts deferred in theseaccounts are recorded in earnings as the hedged purchase or sales transactionis settled. This could include the purchase or sale of energy or energy-relatedproducts, the use of natural gas to generate electric energy or gas purchasedfor resale.

As ofDec. 31, 2006, 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 immaterial ineffectiveness related to commodity cash flow hedges during theyear ended Dec. 31, 2006 and no ineffectiveness during the year ended Dec. 31,2005.

***Interest Rate Cash Flow Hedges***— PSCo enters into****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.

As ofDec. 31, 2006, PSCo had net gains of approximately $1.5 million in AccumulatedOther Comprehensive Income that it expects to recognize in earnings during thenext 12 months.

PSCo had no ineffectiveness related to interest rate cash flow hedgesduring the years ended Dec. 31, 2006 and 2005, respectively.

***Financial Impact of Qualifying Cash Flow Hedges***—The impact of qualifying cash flow hedges on PSCo’s Other Comprehensive Income,included in the Consolidated Statements of Stockholder’s Equity, is detailed inthe following table:
| **(Millions of Dollars)**                                                 | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|
| Accumulated  other comprehensive loss related to hedges at Dec. 31, 2003            |       | $          | 17.2       |   |
| After-tax net  unrealized gains related to derivative 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       |   |
|                                                                                |       |       |       |
| After-tax net  unrealized losses related to derivatives accounted for as hedges     |       | (0.1       | )          |
| After-tax net  realized gains on derivative transactions reclassified into earnings |       | (1.5       | )          |
| Accumulated other  comprehensive income related to hedges at Dec. 31, 2006          |       | $          | 12.6       |   |

 

**Normal Purchases or Normal SalesContracts**

PSCo enters into contracts for the purchase and sale of commodities foruse in its business operations.  SFAS No.133 requires a company to evaluate these contracts to determine whether thecontracts are derivatives.  Certaincontracts that meet the definition of a derivative may be exempted from SFASNo. 133 as normal purchases or normal sales.

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

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In 2003, as a result of FASB Statement 133 Implementation Issue No.C20, PSCo began recording several long-term power purchase agreements at fairvalue due to accounting requirements related to underlying price adjustments.As these purchases are recovered through normal regulatory recovery mechanismsin the respective jurisdictions, the changes in fair value for these contractswere offset by regulatory assets and liabilities. During the first quarter of2006, PSCo qualified these contracts under the normal purchase exception. Basedon this qualification, the contracts will no longer be adjusted to fair valueand the previous carrying value of these contracts will be amortized over theremaining contract lives along with the offsetting regulatory balances.

Normal purchases and normal sales contracts are accounted for asexecutory contracts.

***Commodity TradingContracts***- The fair value of commodity trading contractsas of Dec. 31, 2006 and 2005 was $(0.6) million and $2.1 million, respectively.

***Hedging Contracts***-The fair value of qualifying cash flowhedges at Dec. 31, 2006 and 2005 was $3.1 million and $1.0 million,respectively.

For a further discussion of other financialinstruments at PSCo, see Note 10 to the Consolidated Financial Statements.

**10.Financial Instruments**

The estimated Dec. 31fair values of PSCo’s recorded financial instruments were as follows:
| ** **                                 | ** ** | **2006**                 | ** ** | **2005**            | ** ** |
|--------------------------------------------|------------|--------------------------|------------|---------------------|------------|
| **(Thousands of Dollars)**       | ** ** | **Carrying Amount** | ** ** | **Fair Value** | ** ** | **Carrying Amount** | ** ** | **Fair Value** | ** ** |
| Long-term  investments                     |       | $                        | 11,144     |                | $          | 11,144 |   | $ | 12,877 |   | $ | 12,877 |   |
| Long-term debt,  including current portion |       | $                        | 1,946,657  |                | $          | 2,023,551 |   | $ | 2,072,307 |   | $ | 2,187,802 |   |

 

The fair value of cash and cash equivalents, notes and accountsreceivable and notes and accounts payable are not materially different fromtheir carrying amounts.  The fair valueof PSCo’s long-term investments are estimated based on quoted market prices forthose or similar investments.  The fairvalue of PSCo’s long-term debt is estimated based on the quoted market pricesfor the same or similar issues or the current rates for debt of the sameremaining maturities and credit quality.

The fair value estimatespresented are based on information available to management as of Dec. 31, 2006and 2005. These fair value estimates have not been comprehensively revalued forpurposes of these Consolidated Financial Statements since that date, andcurrent estimates of fair values may differ significantly.

# **Lettersof Credit**

PSCo use letters ofcredit, generally with terms of one year, to provide financial guarantees forcertain operating obligations.  At Dec.31, 2006, there was $6.0 million of letters of credit outstanding. The contractamounts of these letters of credit approximate their fair value and are subjectto fees determined in the marketplace.

**11. RateMatters**

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

***FERC TransmissionRate Case*****—On Sept. 2, 2004, Xcel Energy filed on behalf of both PSCo and SPS anapplication to increase wholesale transmission service and ancillary servicerates within the Xcel Energy joint open access transmission tariff. PSCo andSPS requested an increase in annual transmission service and ancillary servicesrevenues of $6.1 million. OnFeb. 6, 2006, the parties in the proceeding submitted an uncontested offerof settlement that contains a $1.6 million rate increase for PSCo, a formulatransmission service rate for PSCo, a 10.5 percent rate of return on common equity,and the phased inclusion of PSCo’s 345 kilovolt tie line costs in wholesaletransmission service rates. On April 5, 2006, the FERC issued an orderapproving the uncontested settlement. PSCo placed the final rates in effect onJune 1, 2006 and made refunds of approximately $3.7 million.

**Pendingand Recently Concluded Regulatory Proceedings - CPUC**

***Electric Rate Case —***In April 2006, PSCo filed with the CPUC to increase electricity rates by $208million annually, beginning Jan. 1, 2007.  The request was based on twocomponents, including an increase in base rate revenues of $178 million and anestimated $30 million increase in PCCA revenue.  The base rate request wasbased on a return on equity of 11 percent, an equity ratio of 59.9 percent andan electric rate base of $3.4 billion.  No interim rate increase wasimplemented.  The PCCA request was based on 2007 projected costs.

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OnOct. 20, 2006, PSCo entered into a comprehensive settlement agreement withseveral of the parties to the case.  On Nov. 20, 2006, the CPUC issued awritten order approving the settlement with new rates effective Jan. 1,2007.   The settlement provides for anincrease in base rates of $107 million, based on a 10.50 percent return onequity, an estimated $39.4 million in PCCA revenue and an estimated $4.6million in ECA revenue to recover certain WindSource program costs for a totalincrease of $151 million.  In addition,PSCo is permitted an incentive for its performance on achieving fuel and purchasedenergy savings as well as for its generation based wholesale margins.

***Natural GasRate Case*****—On Dec. 1, 2006, PSCo filed with the CPUC a request to increase natural gasrates by $41.5 million, annually, representing an overall increase of 2.96percent.  The request is based on a requestedcapital structure of 60.17 percent common equity, a return on common equity of11 percent and a rate base of approximately $1.1 billion.  It is anticipated that new rates will becomeeffective in the third quarter of 2007.

***Quality of Service Plan*** — The PSCo QSPprovides for bill credits to Colorado retail customers, if PSCo does notachieve certain operational performance targets. During the second quarter of2006, PSCo filed its calendar year 2005 operating performance results forelectric service unavailability, phone response time, customer complaints,accurate meter reading and natural gas leak repair time measures.  PSCo did not achieve the 2005 performancetargets for the electric service unavailability measure creating a bill creditobligation of $13.6 million. Additionally, in accordance with a prior agreement, PSCo invested anadditional $11 million in 2006 toward improving reliability.  As a result, PSCo will not be required to payany bill credits that may be owed for 2006 performance results for electricservice unavailability.    The maximumpotential bill credit obligation for 2006 related to permanent natural gas leakrepair and natural gas meter reading errors is approximately $1.6 million.  PSCo does not anticipate any bill creditswill be due customers based on the 2006 performance targets.

**12.Commitments and Contingent Liabilities**

***Tax Matters -***In April 2004, XcelEnergy filed a lawsuit against the U.S. government in the U.S. District Courtfor the District of Minnesota to establish its right to deduct the interestexpense that had accrued during tax years 1993 and 1994 on policy loans relatedto the COLI policies.

AfterXcel Energy filed this suit, the IRS sent two statutory notices of deficiencyof tax, penalty and interest for 1995 through 1999. Xcel Energy has filed U.S.Tax Court petitions challenging those notices. Xcel Energy anticipates thedispute relating to its interest expense deductions will be resolved in therefund suit that is pending in the Minnesota Federal District Court and the TaxCourt petitions will be held in abeyance pending the outcome of the refundlitigation. In the third quarter of 2006, Xcel Energy also received a statutorynotice of deficiency from the IRS for tax years 2000 through 2002 and timelyfiled a Tax Court petition challenging the denial of the COLI interest expensedeductions for those years.

OnOct. 12, 2005, the district court denied Xcel Energy’s motion for summaryjudgment on the grounds that there were disputed issues of material fact thatrequired a trial for resolution. At the same time, the district court deniedthe government’s motion for summary judgment that was based on its contentionthat PSCo had lacked an insurable interest in the lives of the employeesinsured under the COLI policies. However, the district court granted XcelEnergy’s motion for partial summary judgment on the grounds that PSCo did havethe requisite insurable interest.

On May5, 2006, Xcel Energy filed a second motion for summary judgment. On Aug. 18,2006, the U.S. government filed a second motion for summary judgment.  On Feb. 14, 2007, the Magistrate Judge issuedhis Report and Recommendation (R&R) to the Judge concerning both motions.In his R&R the Magistrate Judge recommends both motions be denied due tofact issues in dispute. Both parties will have an opportunity to fileobjections by March 5, 2007 to the Magistrate Judge’s recommendations. TheJudge will then have broad authority to, among other things, accept or rejectthe recommendations in whole or in part. If both sides’ motions are ultimately denied, a trial is set to begin onJuly 24, 2007.

XcelEnergy believes that the tax deduction for interest expense on the COLI policyloans is in full compliance with the tax law. Accordingly, PSRI has not recordedany provision for income tax or related interest or penalties, and hascontinued to take deductions for interest expense on policy loans on its incometax returns for subsequent years. The litigation could require several years toreach final resolution. Defense of Xcel Energy’s position may requiresignificant cash outlays, which may or may not be recoverable in a courtproceeding. The ultimate resolution of this matter is uncertain and could havea material adverse effect on PSCo’s financial position, results of operationsand cash flows.

Shouldthe IRS ultimately prevail on this issue, tax and interest payable through Dec.31, 2006, would reduce earnings by an estimated $421 million. Xcel Energy hasreceived formal notification that the IRS will seek penalties. If penalties(plus 

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associatedinterest) also are included, the total exposure through Dec. 31, 2006, isapproximately $499 million. In addition, PSCo’s annual earnings for 2007 wouldbe reduced by approximately $49 million, after tax, if COLI interest expensedeductions were no longer available.

*COLI Dow Chemical Court Decision*****- On Jan. 23, 2006, the 6th Circuit of theU.S. Court of Appeals issued an opinion in a federal income tax case involvingthe interest deductions for a COLI program at Dow Chemical Company.  The 6th Circuit denied the tax deductions andreversed the decision of the trial court in the case.

XcelEnergy has analyzed the impact of the Dow decision on its pending COLIlitigation and concluded there are significant factual differences between itscase and the Dow case.  The court’sopinion in the Dow case outlined three indicators of potential economicbenefits to be examined in a COLI case and noted that the outcome of COLI casesis very fact determinative.  These indicators are:

·       Positive pre-deduction cashflows;

·       Mortality gains; and

·       The buildup of cash values.

In a split decision, the 6thCircuit found that the Dow COLI plans possessed none of these indicators ofeconomic substance.  However, in XcelEnergy’s COLI case, the plans were projected to have sizeable pre-deductioncash flows, based upon the relevant assumptions when purchased.  Moreover, the plans presented the opportunityfor mortality gains that were not eliminated either retroactively orprospectively.  Xcel Energy’s COLI planshad no provision for giving back any mortality gains that it might realize. Inaddition, Xcel Energy’s plans had large cash value increases that were notencumbered by loans during the first seven years of the policies.  Consequently, Xcel Energy believesthat the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strongmerits.

***Leases*****— PSCo leases a variety of equipment and facilities used in thenormal course of business. Two of these leases qualify as capital leases andare accounted for accordingly. The capital leases contractually expire in 2025and 2028.  The assets and liabilitiesacquired under capital leases are recorded at the lower of fair-market value orthe present value of future lease payments and are amortized over their actualcontract term in accordance with practices allowed by regulators.

Following is a summary ofproperty held under capital leases:

| (Millions of Dollars)           | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Storage,  leaseholds and rights           |       | $        | 40.5       |     | $          | 40.5 |   |
| Gas pipeline                              |       | 20.7     |       | 20.7     |       |
|                                      |       | 61.2     |       | 61.2     |       |
| Less:  Accumulated amortization           |       | (15.0    | )          | (13.6    | )          |
| Total property  held under capital leases |       | $        | 46.2       |     | $          | 47.6 |   |

 

The remainder of theleases, primarily for office space, railcars, generating facilities, trucks,cars and power-operated equipment are accounted for as operating leases.  Rental expense under operating leaseobligations was approximately $17.1 million, $19.6 million and $17.6 millionfor 2006, 2005 and 2004, respectively.

Future commitments under noncancellableoperating and capital leases with terms in excess of one year are:

| (Millions of Dollars)      | ** ** | **Operating Leases** | ** ** | **Capital Leases** | ** ** |
|--------------------------------------|------------|---------------------------|------------|-------------------------|------------|
| 2007                                 |       | $                         | 8.8        |                    | $          | 6.3 |   |
| 2008                                 |       | $                         | 8.2        |                    | 6.1        |   |
| 2009                                 |       | $                         | 8.1        |                    | 6.0        |   |
| 2010                                 |       | $                         | 8.0        |                    | 5.8        |   |
| 2011                                 |       | $                         | 7.9        |                    | 5.6        |   |
| Thereafter                           |       | $                         | 34.0       |                    | 62.4       |   |
| Total minimum obligation             |       |                      |       | $                       | 92.2       |   |
| Interest  component of obligation    |       |                      |       | (46.0                   | )          |
| Present value of  minimum obligation |       |                      |       | $                       | 46.2       |   |

 

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***Capital Commitments —***The estimatedcost, as of Dec. 31, 2006, of the capital expenditure programs and othercapital requirements of PSCo was approximately $690 million in 2007, $635million in 2008 and $515 million in 2009. PSCo’s capital expenditure forecast includes the following majorproject:

*Comanche3 -*Comanche 3, a 750-MW coal-fired plant being built inColorado is expected to cost approximately $1.35 billion, with majorconstruction initiated in 2006 and completed in the fall of 2009.  The CPUC has approved sharing one-thirdownership of this plant with other parties. Consequently, PSCo’s investment in Comanche 3 will be approximately $1billion.

The capital expenditureprograms of PSCo are subject to continuing review and modification. Actualutility construction expenditures may vary from the estimates due to changes inelectric and natural gas projected load growth regulatory decisions, thedesired reserve margin and the availability of purchased power, as well asalternative plans for meeting PSCo’s long-term energy needs. In addition, PSCo’songoing evaluation of compliance with future requirements to installemission-control equipment, and merger, acquisition and divestitureopportunities to support corporate strategies may impact actual capitalrequirements.

***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 2007 and2025. In addition, PSCo may be 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 minimum purchase obligation for PSCo under thesecontracts as of Dec. 31, 2006, is as follows:

| Coal       | ** ** | **Natural Gas  Supply**        | ** ** | **Gas Storage &  Transportation** | ** ** |
|------------|------------|-------------------------------------|------------|-------------------------------------------------|------------|
| ** ** | ** ** | **(Millions of Dollars)** | ** ** | ** **                                      | ** ** |
| $          | 632        |                                | $          | 766                                             |       | $ | 730 |   |
|            |            |                                     |            |                                                 |            |  |  |  |

 

***Purchased Power Agreements****—*PSCo has entered into agreements withutilities and other energy suppliers for purchased power to meet system loadand energy requirements, replace generation from company-owned units undermaintenance and during outages, and meet operating reserve obligations. PSCohas various pay-for-performance contracts with expiration dates through theyear 2027. In general, these contracts provide for capacity payments, subjectto meeting certain contract obligations and energy payments based on actualpower taken under the contracts. Certain contractual payment obligations areadjusted based on indices.  However, theeffects of these price adjustments are mitigated through cost-of-energy rate adjustmentmechanisms.

At Dec. 31, 2006, theestimated future payments for capacity that PSCo is obligated to purchase,subject to availability, were as follows (Millions of Dollars):

| 2007                 |   | $       | 410.1   |   |
|----------------------|--------|---------|---------|--------|
| 2008                 |   | 401.3   |    |
| 2009                 |   | 411.9   |    |
| 2010                 |   | 399.5   |    |
| 2011                 |   | 392.1   |    |
| 2012 and  thereafter |   | 2,353.6 |    |
| Total                |   | $       | 4,368.5 |   |

 

**Environmental Contingencies**

PSCo has been, or iscurrently, involved with the cleanup of contamination from certain hazardoussubstances at several sites. In many situations, PSCo believes it will recoversome portion of these costs through insurance claims. Additionally, whereapplicable, PSCo is pursuing, or intends to pursue, recovery from otherpotentially responsible parties and through the rate regulatory process.  New and changing federal and stateenvironmental mandates can also create added financial liabilities for PSCo,which are normally recovered through the rate regulatory process.   To the extent any costs are not recoveredthrough the options listed above, PSCo would be required to recognize anexpense.

***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 situationsincluding the following categories of sites:

·       site of a formermanufactured gas plant (MGP) operated by PSCo or its predecessors; and

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

PSCo records a liability when enough information is obtained to developan estimate of the cost of environmental remediation and revises the estimateas information is received.  Theestimated remediation cost may vary materially.

To estimate the cost toremediate these sites, assumptions are made where facts are not fully known.For instance,  assumptions may be madeabout the nature and extent of site contamination, the extent of required cleanupefforts, costs of alternative cleanup methods and pollution-controltechnologies, the period over which remediation will be performed and paid for,changes in environmental remediation and pollution-control requirements, thepotential effect of technological improvements, the number and financialstrength of other PRPs and the identification of new environmental cleanupsites.

Estimates are revised as facts become known..  At Dec. 31, 2006, the liability for the costof remediating these sites was estimated to be $1.3 million, of which $0.4million was considered to be a current liability.  Some of the cost of remediation may berecovered from:

·       insurance coverage;

·       other parties that havecontributed to the contamination; and

·       customers.

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

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

***Fort Collins Manufactured Gas Plant Site*—**Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated anMGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926,after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and hassold most of the property.  An oilysubstance similar to MGP byproducts was discovered in the Cache la PoudreRiver.  On Nov. 10, 2004, PSCoentered into an agreement with the EPA, the city of Fort Collins and SchraderOil Co., under which PSCo performed remediation and monitoring work.  PSCo has substantially completed work at thesite, with the exception of ongoing maintenance and monitoring.  In May 2005, PSCo filed a natural gasrate case with the CPUC requesting recovery of cleanup costs at the FortCollins MGP site spent through March 2005, which amounted to $6.2 million,to be amortized over four years.  PSCoreached a settlement agreement with the parties in the case.  The CPUC approved the settlement agreement onJan. 19, 2006 and the final order became effective on Feb. 3, 2006,with rates effective Feb. 6, 2006. In November 2006, PSCo filed a natural gas rate case with the CPUCrequesting recovery of additional clean-up costs at the Fort Collins MGP sitespent through September 2006, plus unrecovered amounts previously authorizedfrom the last rate case, which amounted to $10.8 million to be amortized overfour years.  The total amount PSCo isrequesting be recovered from customers is $13.1 million.

InApril 2005, PSCo brought a contribution action against Schrader Oil Co.and related parties alleging Schrader Oil Co. released hazardous substancesinto the environment and these releases caused MGP byproducts to migrate to the Cache La Poudre River, therebysubstantially increasing the scope and cost of remediation.  PSCo requested damages, including a portionof the costs PSCo incurred to investigate and remove contaminated sedimentsfrom the Cache la Poudre River.  OnDec. 14, 2005, the court denied Schrader’s request to dismiss the PSCosuit.  On Jan. 3, 2006, Schraderfiled a response to the PSCo complaint and a counterclaim against PSCo for itsresponse costs under the Comprehensive Environmental Response Compensation andLiability Act (CERCLA) and under the Resource Conservation and Recovery Act(RCRA).  Schrader has alleged as part ofits counterclaim an “imminent and substantial endangerment” of its property asdefined by RCRA.  In September 2006, PSCofiled a Motion For Partial Summary Judgment to dismiss Schrader’s RCRAclaim.  PSCo believes the allegationswith respect to PSCo are without merit and will vigorously defend itself.

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

***Asbestos Removal*—**Some of PSCo’sfacilities contain asbestos. Most asbestos will remain undisturbed until thefacilities that contain it are demolished or renovated.  PSCo has recorded an estimate for finalremoval of the asbestos as an asset retirement obligation.  See additional discussion of asset retirementobligations below.  It may be necessaryto remove some asbestos to perform maintenance or make improvements to otherequipment. The cost of removing asbestos as part of other work is immaterialand is recorded as incurred as operating expenses for maintenance projects,capital expenditures for construction projects or removal costs for demolitionprojects.

***Other Environmental Requirements***

***Regional Haze Rules*** — On June 15,2005, the EPA finalized amendments to the July 1999 regional haze rules. Theseamendments apply to the provisions of the regional haze rule that requireemission controls, known as best available retrofit 

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technology (BART), forindustrial facilities emitting air pollutants that reduce visibility by causingor contributing to regional haze.  SomePSCo generating facilities will be subject to BART requirements.

The EPA requiresstates to develop implementation plans to comply with BART byDecember 2007. States are required to identify the facilities that willhave to reduce emissions under BART and then set BART emissions limits forthose facilities. On May 30, 2006, the Colorado Air Quality Control Commissionpromulgated BART regulations requiring certain major stationary sources toevaluate and install, operate and maintain BART technology or an approved BARTalternative to make reasonable progress toward meeting the national visibilitygoal. On Aug. 1, 2006, PSCo submitted its BART alternatives analysis to theColorado Air Pollution Control Division. As set forth in its analysis, PSCoestimates that implementation of the BART alternatives will cost approximately$211 million in capital costs, which includes approximately $62 million inenvironmental upgrades for the existing Comanche Station project, which areincluded in the capital budget. PSCo expects the cost of any required capitalinvestment will be recoverable from customers. Emissions controls are expectedto be installed between 2010 and 2012.

***Clean Air Mercury Rule***— InMarch 2005, the EPA issued the Clean Air Mercury Rule (CAMR), whichregulates mercury emissions from power plants for the first time. PSCocontinues to evaluate the strategy for complying with CAMR. Compliance may beachieved by either adding mercury controls or purchasing allowances or acombination of both.  In February 2007,the Colorado Air Quality Control Commission passed a mercury rule.  The rule was based on a negotiated rule thatwas agreed upon by participating environmental groups, utilities, localgovernment coalitions, and the Colorado Air Pollution Control Division. Therule requires controls to be installed at Pawnee Station in 2012 and all otherColorado units by 2014.  PSCo isevaluating the emission controls required to meet the new rule and is currentlyunable to provide a capital cost estimate

***Federal Clean Water Act***— The federalClean Water Act requires EPA to regulate cooling water intake structures  to assure that these structures reflect the “besttechnology available” for minimizing adverse environmental impacts. InJuly 2004, the EPA published phase II of the rule, which applies to existingcooling water intakes at steam-electric power plants. Several lawsuits werefiled against the EPA in the United States Court of Appeals for the SecondCircuit challenging the phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtuallyevery aspect of the rule to the EPA for reconsideration. It is unclear whetherEPA will stay the deadlines in the rule until the remanded rulemaking isfinished.  As a result, the rule’scompliance requirements and associated deadlines are currently unknown. It isnot possible to provide an accurate estimate of the overall cost of thisrulemaking at this time due to the many uncertainties involved.

***Notice of Violation*** — On July 1,2002, PSCo received a Notice of Violation (NOV) from the EPA allegingviolations of the New Source Review (NSR) requirements of the Clean Air Act(CAA) at the Comanche and Pawnee plants in Colorado. The NOV specificallyalleges that various maintenance, repair and replacement projects undertaken atthe plants in the mid- to late-1990s should have required a permit under theNSR process.  PSCo believes it has actedin full compliance with the CAA and NSR process. It believes that the projectsidentified in the NOV fit within the routine maintenance, repair and replacementexemption contained within the NSR regulations or are otherwise not subject tothe NSR requirements. PSCo also believes that the projects would be expresslyauthorized under the EPA’s NSR equipment replacement rulemaking promulgated inOctober 2003. 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.

**AssetRetirement Obligations**

PSCo records future plantremoval obligations as a liability at fair value with a corresponding increaseto the carrying values of the related long-lived assets in accordance with SFASNo. 143 — “Accounting for Asset Retirement Obligations” (SFASNo. 143).  This liability will beincreased over time by applying the interest method of accretion to theliability, and the capitalized costs will be depreciated over the useful lifeof the related long-lived assets.  Therecording of the obligation for regulated operations has no income statementimpact due to the deferral of the adjustments through the establishment of aregulatory asset pursuant to SFAS No. 71.

***Recorded Asset Retirement Obligations (ARO) —***Asset retirement obligations have been recorded for steam production, electrictransmission and distribution and natural gas distribution.  The steam production obligation includesasbestos and ash-containment facilities. The asbestos recognition associated with the steam production includescertain plants at PSCo.  Generally, thisasbestos abatement removal obligation originated in 1973 with the Clean AirAct, which applied to the demolition of buildings or removal of equipmentcontaining asbestos that can become airborne on removal.  Asset retirement obligations also have beenrecorded  for PSCo steam productionrelated to ash-containment facilities such as bottom ash ponds, evaporationponds and solid waste landfills. The origination date on the ARO recognitionfor ash-containment facilities at steam plants was the in-service date ofvarious facilities.

PSCo recognized an AROfor the retirement costs of its natural gas mains.  In addition, an ARO was recognized for theremoval of electric, transmission and distribution equipment.  The electric transmission and distributionARO consists of 

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many small potentialobligations associated with polychlorinated biphenyls (PCBs), mineral oil,storage tanks, treated poles, lithium batteries, mercury and street lightinglamps.  These electric and natural gasassets have many in-service dates for which it is difficult to assign theobligation to a particular year. Therefore, the obligation was measured using an average service life.

If PSCo had implementedFIN No. 47 at Jan. 1, 2005, the liability for asset retirement obligationswould have increased by $12.1 million.

A reconciliation of thebeginning and ending aggregate carrying amounts of PSCo’s asset retirementobligations is shown in the table below for the 12 months ended Dec. 31,2006  Dec. 31, 2005, respectively:
| **(Thousands of Dollars)**    | ** ** | **Beginning  Balance  Jan. 1, 2006** | ** ** | **Liabilities  Recognized** | ** ** | **Liabilities  Settled** | ** ** | **Accretion** | ** ** | **Revisions  To Prior  Estimates** | ** ** | **Ending  Balance  Dec. 31, 2006** | ** ** |
|-----------------------------------------|------------|------------------------------------------------|------------|-----------------------------|------------|--------------------------|------------|---------------|------------|-----------------------------------------|------------|----------------------------------------------|------------|
| ** **                              | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| **Electric  Utility Plant:**            | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| Steam production  asbestos              |       | $                                              | 9,099      |                        | $          | —                   |       | $             | —     |                                    | $          | 535                                          |       | $ | — |   | $ | 9,634 |   |
| Steam production  ash containment       |       | 3,720                                          |       | —                      |       | —                   |       | 230           |       | (44                                     | )          | 3,906                                        |       |
| Electric  transmission and distribution |       | 700                                            |       | —                      |       | —                   |       | 18            |       | (125                                    | )          | 593                                          |       |
| **Gas  Utility Plant:**                 | ** ** | ** **                                     | ** ** | ** **                  | ** ** | ** **               | ** ** | ** **    | ** ** | ** **                              | ** ** | ** **                                   | ** ** |
| Gas transmission  and distribution      |       | 28,449                                         |       | —                      |       | —                   |       | 706           |       | 47                                      |       | 29,202                                       |       |
| Total liability                         |       | $                                              | 41,968     |                        | $          | —                   |       | —        |       | $                                       | 1,489      |                                         | $          | (122 | ) | $ | 43,335 |   |
|                                         |            |                                                |            |                             |            |                          |            |               |            |                                         |            |                                              |            |  |  |  |  |  |  |

 
| **(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 |   |
|                                         |            |                                                |            |                             |            |                          |            |               |            |                                         |            |                                              |            |  |  |  |  |  |  |

 

***Indeterminate Asset Retirement Obligations —***PSCohas underground natural gas storage facilities that have special closurerequirements for which the final removal date cannot be determined.

***Removal Costs***- PSCo accrues anobligation for plant removal costs for generation, transmission anddistribution facilities.  Generally, theaccrual of future 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 ofestimated future removal costs are considered Regulatory Liabilities under SFASNo. 71. Removal costs as of Dec. 31, 2006 and Dec. 31, 2005 were $389 millionand $377 million, respectively.

**LegalContingencies**

In the normal course ofbusiness, PSCo is party to routine claims and litigation arising from prior andcurrent operations. PSCo is actively defending these matters and has recorded aliability related to the probable cost of settlement or other disposition whenit can be reasonably estimated.

***Carbon Dioxide Emissions Lawsuit***— OnJuly 21, 2004, the attorneys general of eight states and New York City, aswell as 

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several environmentalgroups, filed lawsuits in U.S. District Court for the Southern District of NewYork against five utilities, including Xcel Energy, to force reductions incarbon dioxide (CO2)emissions. Although PSCo is not named as a party to this litigation, therequested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effecton PSCo. The other utilities include American Electric Power Co., Southern Co.,Cinergy Corp. and Tennessee Valley Authority. CO2 isemitted whenever fossil fuel is combusted, such as in automobiles, industrialoperations and coal- or natural gas-fired power plants. The lawsuits allegethat CO2 emitted by each company is a public nuisanceas defined under state and federal common law because it has contributed toglobal warming. The lawsuits do not demand monetary damages. Instead, thelawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energyand four other utility companies filed a motion to dismiss the lawsuit,contending, among other reasons, that the lawsuit is an attempt to usurp thepolicy-setting role of the U.S. Congress and the president. On Sept. 19, 2005,the judge granted the defendants’ motion to dismiss on constitutional grounds.Plaintiffs filed an appeal to the Second Circuit Court of Appeals. Oralarguments were presented on June 7, 2006 and a decision on the appeal ispending.

***Payne et al. vs.PSCo et al.***- In late October 2003, there was a wildfirein Boulder County, Colorado.  There wasno loss of life, but there was property damage associated with this fire. OnOct. 28, 2005, an action against PSCo relating to this fire was filed inBoulder County District Court. There are 22 plaintiffs, including individuals,the City of Jamestown and two companies, and three co-defendants, includingPSCo. Plaintiffs have asserted that a tree falling into PSCo distribution linesmay have caused the fire. Discovery is nearly complete, and the case is set togo to trial commencing July 30, 2007. A motion for partial summary judgment hasbeen filed by PSCo and its co-defendants.  PSCo is continuing to  vigorouslydefend itself against the claims asserted in this lawsuit . This lawsuit is notexpected to have a material financial impact and PSCo believes that itsinsurance coverage will cover any liability in this matter.

***Comanche 3 PermitLitigation***- On Aug. 4, 2005, Citizens for Clean Air andWater in Pueblo and Southern Colorado and Clean Energy Action filed a complaintagainst the Colorado Air Pollution Control Division alleging that the Divisionimproperly granted permits to PSCo under Colorado’s Prevention of SignificantDeterioration program for the construction and operation of Comanche 3. PSCointervened in the case.  On June 20,2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits hadbeen properly granted and plaintiffs’ claims to the contrary were withoutmerit. Plaintiffs have appealed this decision. On Nov. 22, 2006, plaintiffs filed their opening briefs. PSCo’s responsewas filed Dec. 26, 2006. The Colorado Court of Appeals is expected to rule onthe appeal in 2007.

***Comer vs. Xcel Energy Inc. et al.***— OnApril 25, 2006, Xcel Energy received notice of a purported class action lawsuitfiled in U.S. District Court for the Southern District of Mississippi. AlthoughPSCo is not named as a party to this litigation, if the litigation ultimatelyresults in an unfavorable outcome for Xcel Energy, it could have a materialadverse effect on PSCo. The lawsuit names more than 45 oil, chemical andutility companies, including Xcel Energy, as defendants and alleges thatdefendants’ CO2 “were a proximate and direct cause of the increase in thedestructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories,including negligence, and public and private nuisance and seek damages relatedto the loss resulting from the hurricane. Xcel Energy believes this lawsuit iswithout merit and intends to vigorously defend itself against these claims. OnJuly 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in itsentirety.

***Qwest vs. XcelEnergy Inc.*** - On June 24, 2004, an employee of PSCo wasinjured when a pole owned by Qwest malfunctioned.  The employee is seeking damages ofapproximately  $7 million. On Sept. 6,2005, an action against Qwest relating to incident was filed in Denver DistrictCourt by the employee.  On April 18,2006, Qwest filed a third party complaint against PSCo based on terms in ajoint pole use agreement between Qwest and PSCo.  Pursuant to this agreement, Qwest hasasserted that PSCo had an affirmative duty to properly train and instruct itsemployees on pole safety, including testing the pole for soundness beforeclimbing.  PSCo filed a counterclaim onMay 15, 2006, against Qwest asserting Qwest had a duty to PSCo and anobligation under the contract to maintain its poles in a safe and serviceablecondition.  This case is still in thediscovery phase and set for jury trial beginning May 14, 2007.

**13. Regulatory Assets and Liabilities**

PSCo’s financialstatements are prepared in accordance with the provisions of SFAS No. 71, asdiscussed in Note 1 to the Consolidated Financial Statements. Under SFAS No.71, regulatory assets and liabilities can be created for amounts thatregulators may allow to be collected, or may require to be paid back tocustomers in future electric and natural gas rates.  Any portion of the business that is not rateregulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of PSCo no longerallow for the application of SFAS No. 71 under GAAP, PSCo would be required torecognize the write-off of regulatory assets and liabilities in its statementof income.  The components of unamortizedregulatory assets and liabilities on the balance sheets of PSCo are:

 

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| ** **                                      | ** ** | **See**  | ** ** | **Remaining Amortization** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------------|------------|----------|------------|---------------------------------|------------|------------|------------|------------|------------|
| **(Thousands of Dollars)**            | ** ** | **Note** | ** ** | **Period**                      | ** ** | **2006**   | ** ** | **2005**   | ** ** |
| Regulatory Assets:                              |       |     |       |                            |       |       |       |       |       |
| Pension and  employee benefit obligations       |       | 7        |       | Various                         |       | $          | 386,346    |       | $          | 27,234 |   |
| Conservation  programs (a)                      |       |     |       | Various                         |       | 70,572     |       | 59,114     |       |
| AFDC recorded in  plant (a)                     |       |     |       | Plant  lives                    |       | 39,722     |       | 40,168     |       |
| Contract  valuation adjustments (b)             |       | 9        |       | Term  of related contract       |       | 39,131     |       | 58,214     |       |
| Losses on  reacquired debt                      |       | 1        |       | Term  of related debt           |       | 24,315     |       | 26,228     |       |
| Net asset  retirement obligations               |       |     |       | Plant  lives                    |       | 13,664     |       | 11,789     |       |
| Environmental  costs                            |       | 11       |       | Four  years                     |       | 8,522      |       | —     |       |
| Plant asset  recovery (Pawnee II and Metro Ash) |       |     |       | Six  months                     |       | 2,452      |       | 7,355      |       |
| Rate case costs                                 |       | 1        |       | Various                         |       | 2,190      |       | 1,699      |       |
| Other                                           |       |     |       | Various                         |       | 2,102      |       | —     |       |
| Total regulatory  assets                        |       |     |       |                            |       | $          | 589,016    |       | $          | 231,801 |   |
| Regulatory  Liabilities:                        |       |     |       |                            |       |       |       |       |       |
| Plant removals  costs                           |       | 11       |       |                            |       | $          | 389,056    |       | $          | 377,343 |   |
| Investment tax  credit deferrals                |       |     |       |                            |       | 35,764     |       | 38,134     |       |
| Contract  valuation adjustments (b)             |       | 9        |       |                            |       | —     |       | 46,827     |       |
| Deferred income  tax adjustments                |       |     |       |                            |       | 31,146     |       | 30,031     |       |
| Renewable  resource requirements                |       |     |       |                            |       | 14,289     |       | —     |       |
| Total regulatory  liabilities                   |       |     |       |                            |       | $          | 470,255    |       | $          | 492,335 |   |

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(a)             Earns a return oninvestment in the ratemaking process. These amounts are amortized consistentwith recovery in rates.

(b)            Includesthe fair value of certain long-term contracts used to meet native energyrequirements.

**14. Segmentsand Related Information**

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

·       PSCo’s Regulated ElectricUtility generates, transmits and distributes electricity in Colorado. Inaddition, this segment includes sales for resale and provides wholesaletransmission service to various entities in the United States. RegulatedElectric Utility also includes PSCo’s commodity trading operations.

·       PSCo’s Regulated NaturalGas Utility transports, stores and distributes natural gas in portions ofColorado.

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

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

·       directly assigned whereverapplicable;

·       allocated based on costcausation allocators wherever applicable; or

·       allocated based on ageneral allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the sameas those described in Note 1 to the Consolidated Financial Statements. Thesesegments are managed separately because the revenue streams are dependent uponregulated rate recovery which are separately determined for each segment.

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| ** **                                  | ** ** | ** **                | ** ** | **Regulated**        | ** ** | ** ** | ** ** | ** **       | ** ** | ** **       | ** ** |
|---------------------------------------------|------------|---------------------------|------------|----------------------|------------|------------|------------|------------------|------------|------------------|------------|
| ** **                                  | ** ** | **Regulated**             | ** ** | **Natural**          | ** ** | **All**    | ** ** | **Reconciling**  | ** ** | **Consolidated** | ** ** |
| **(Thousands of Dollars)**        | ** ** | **Electric Utility** | ** ** | **Gas Utility** | ** ** | **Other**  | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| **2006**                                    |       |                      |       |                 |       |       |       |             |       |             |       |
| Operating  revenues from external customers |       | $                         | 2,505,445  |                 | $          | 1,262,295  |       | $                | 38,089     |             | $          | — |   | $ | 3,805,829 |   |
| Intersegment  revenues                      |       | 201                       |       | 90                   |       | —     |       | (291             | )          | —           |       |
| Total revenues                              |       | $                         | 2,505,646  |                 | $          | 1,262,385  |       | $                | 38,089     |             | $          | (291 | ) | $ | 3,805,829 |   |
| Depreciation and  amortization              |       | $                         | 177,329    |                 | $          | 56,054     |       | $                | 6,533      |             | $          | — |   | $ | 239,916 |   |
| Financing costs,  mainly interest expense   |       | 95,674                    |       | 26,984               |       | 1,750      |       | (301             | )          | 124,107          |       |
| Income tax  expense (benefit)               |       | 93,429                    |       | 30,049               |       | (41,777    | )          | —           |       | 81,701           |       |
| Segment net  income                         |       | $                         | 170,997    |                 | $          | 57,475     |       | $                | 12,986     |             | $          | — |   | $ | 241,458 |   |
| ** **                                  | ** ** | ** **                | ** ** | ** **           | ** ** | ** ** | ** ** | ** **       | ** ** | ** **       | ** ** |
| **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 |   |

 

**15. RelatedParty Transactions**

Xcel Energy Services Inc.provides management, administrative and other services for the subsidiaries ofXcel Energy, including PSCo. The services are provided and billed to eachsubsidiary in accordance with Service Agreements executed by each subsidiary.Costs are charged directly to the subsidiary which uses the service wheneverpossible, and are allocated if they cannot be directly assigned.

Xcel Energy hasestablished a utility money pool arrangement with the utility subsidiaries andreceived required FERC and state regulatory approvals.  See Note 2 for further discussion of thisborrowing arrangement.

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

Cheyenne Light, Fuel and Power (Cheyenne), a former Xcel Energysubsidiary, purchased all of its electricity requirements from PSCo. During2004, Xcel Energy reached an agreement to sell Cheyenne.  The sale was completed in January 2005.

The table below containssignificant affiliate transactions among the companies and related parties forthe years ended Dec. 31:
| **(Thousands of Dollars)**                     | ** ** | **2006**                   | ** ** | **2005**                   | ** ** | **2004**                   | ** ** |
|----------------------------------------------------------|------------|----------------------------|------------|----------------------------|------------|----------------------------|------------|
| Operating  revenues:                                     |       |                       |       |                       |       |                       |       |
| Electric utility                                         |       | $                          | —     |                       | $          | 2,378                      |       | $ | 48,666 |   |
| Operating  expenses:                                     |       |                       |       |                       |       |                       |       |
| Other operations — paid to Xcel Energy Services Inc |       |     267,307 |       |     256,290 |       |     298,124 |       |
| Interest expense                                         |       | 4,894                      |       | 725                        |       | 886                        |       |
|                                                          |            |                            |            |                            |            |                            |            |  |  |  |

 

55

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Accountsreceivable and payable with affiliates at Dec. 31, was:

 
| ** **                              | ** ** | **2006**       | ** ** | **2005**     | ** ** |
|-----------------------------------------|------------|----------------|------------|--------------|------------|
| ** **                              | ** ** | **Accounts**   | ** ** | **Accounts** | ** ** | **Accounts** | ** ** | **Accounts** | ** ** |
| **(Thousands of Dollars)**    | ** ** | **Receivable** | ** ** | **Payable**  | ** ** | **Receivable** | ** ** | **Payable** | ** ** |
|                                    |       |           |       |         |       |   |   |   |   |
| NSP-Minnesota                           |       | $              | 6,598      |         | $          | — |   | $ | 22,356 |   | $ | 162 |   |
| NSP-Wisconsin                           |       | 1,285          |       | —       |       | — |   | 2,281 |   |
| SPS                                     |       | —         |       | 1,189        |       | 86 |   | — |   |
| Other  subsidiaries of Xcel Energy Inc. |       | 738            |       | 29,102       |       | 25,304 |   | 23,945 |   |
|                                    |       | $              | 8,621      |         | $          | 30,291 |   | $ | 47,746 |   | $ | 26,388 |   |

 

**16. SummarizedQuarterly Financial Data (Unaudited)**

 
| ** **                           | ** ** | **Quarter Ended**       | ** ** |
|--------------------------------------|------------|------------------------------|------------|
| **(Thousands of Dollars)** | ** ** | **March 31, 2006** | ** ** | **June 30, 2006** | ** ** | **Sept. 30, 2006** | ** ** | **Dec. 31, 2006** | ** ** |
|                                 |       |                         |       |   |   |   |   |   |   |
| Revenue                              |       | $                            | 1,267,025  |   | $ | 767,231 |   | $ | 793,724 |   | $ | 977,849 |   |
| Operating income                     |       | 133,087                      |       | 105,348 |   | 99,504 |   | 120,900 |   |
| Net income                           |       | 76,846                       |       | 52,193 |   | 47,358 |   | 65,061 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

 

 
| ** **                           | ** ** | **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 |   |
|                                      |            |                              |            |  |  |  |  |  |  |  |  |  |  |

 

**Item9**— **Changes in andDisagreements With Accountants on Accounting and****Financial Disclosure**

During 2005 and 2006, and through the date of this report, there wereno disagreements with the independent public accountants for PSCo on accountingprinciples or practices, financial statement disclosures or audit scope orprocedures.

**Item9A**— **Controls andProcedures**

**Disclosure Controls and Procedures**

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

**InternalControl Over Financial Reporting**

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

**Item9B**— **Other Information**

None

**PART III**

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

**Item 10 — Directors, Executive Officers, andCorporate Governance**

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

**Item12**— **Security Ownership ofCertain Beneficial Owners and Management and Related Stockholder Matters**

56

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**Item13**— **Certain Relationships,Related Transactions, and Director Independence**

**Item14**— **Principal AccountingFees and Services**

Information concerningfees paid to the principal accountant for each of the last two years iscontained in the Xcel Energy Proxy Statement for its 2007 Annual Meeting ofShareholders, which is incorporated by reference.

**PART IV**

**Item15**— **Exhibits, FinancialStatement Schedules**

1.         Consolidated FinancialStatements:

Reports of Independent Registered Public AccountingFirm **—**For the years ended Dec.31, 2006, 2005 and 2004.

ConsolidatedStatements of Income **—**For the three years ended Dec. 31, 2006, 2005and 2004.

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31, 2006,2005 and 2004.

Consolidated Balance Sheets **—**As of Dec. 31, 2006 and 2005.

 

2.         Schedule II **—**Valuation and Qualifying Accounts andReserves for the years ended Dec. 31, 2006, 2005 and 2004.

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

 
| ** **      | ** ** | **Previous Filing:** | ** ** | ** **  | ** ** | ** **      | ** ** | **Previous Filing:**                 | ** ** | ** **  | ** ** |
|-----------------|------------|----------------------|------------|-------------|------------|-----------------|------------|--------------------------------------|------------|-------------|------------|
| ** **      | ** ** | **Form; Date or**    | ** ** | **Exhibit** | ** ** | ** **      | ** ** | **Form; Date or**                    | ** ** | **Exhibit** | ** ** |
| **Dated as of** | ** ** | **file no.**         | ** ** | **No.**     | ** ** | **Dated as of** | ** ** | **file no.**                         | ** ** | **No.**     | ** ** |
| ** **      | ** ** | ** **           | ** ** | ** **  | ** ** | ** **      | ** ** | ** **                           | ** ** | ** **  | ** ** |
| Nov. 1, 1993    |       | S-3, (33-51167)      |       | 4(b)(2)     |       | Aug. 15, 2002   |       | 10-Q, Sept. 30, 2002                 |       | 4.03        |       |
| Jan. 1, 1994    |       | 10-K, 1993           |       | 4(b)(3)     |       | Sept. 1, 2002   |       | 8-K, Sept. 18, 2002                  |       | 4.01        |       |
| Sept. 2, 1994   |       | 8-K, September 1994  |       | 4(b)        |       | Sept. 15, 2002  |       | 10-Q, Sept. 30, 2002                 |       | 4.04        |       |
| May 1, 1996     |       | 10-Q, June 30, 1996  |       | 4(b)        |       | March 1, 2003   |       | S-3, April 14, 2003 (333-104504)     |       | 4(b)(3)     |       |
| Nov. 1, 1996    |       | 10-K, 1996           |       | 4(b)(3)     |       | April 1, 2003   |       | 10-Q May 15, 2003 (001-03034         |       | 4.02        |       |
| Feb. 1, 1997    |       | 10-Q, March 31, 1997 |       | 4(b)        |       | May 1, 2003     |       | S-4, June 11, 2003 (333-106011)      |       | 4.9         |       |
| April 1, 1998   |       | 10-Q, March 31, 1998 |       | 4(b)        |       | Sept. 1, 2003   |       | 8-K, Sept. 2, 2003 (001-03280        |       | 4.02        |       |
|            |       |                 |       |        |       | Sept. 15, 2003  |       | Xcel 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*   |   | $700,000,000 Credit Agreement dated Dec. 14, 2006  between PSCo and various lenders (Exhibit 99.01 to Form 8-K (file no.  001-03280) dated Dec. 14, 2006).                                                                                                                                                                 |
| 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).                                                              |

 

57

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| 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).                                                                                                                       |
| 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).                                                                                                                                   |

 

58

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| 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.                                                                                                                        |
| 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.                                                                                                                                                                                                            |

 

59

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**SCHEDULE II**

**PUBLICSERVICE COMPANY OF COLORADO**

**VALUATIONAND QUALIFYING ACCOUNTS**

**YearsEnded Dec. 31, 2006, 2005 and 2004**

**(Thousandsof Dollars)**

 
| ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|

 
| ** **                             | ** ** | ** **          | ** ** | **Additions**                | ** ** | ** **            | ** ** | ** **            | ** ** |
|----------------------------------------|------------|---------------------|------------|------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                             | ** ** | **Balance at** | ** ** | **Charged**                  | ** ** | **Charged**           | ** ** | **Deductions**        | ** ** | **Balance** | ** ** |
| ** **                             | ** ** | **beginning**       | ** ** | **to costs &** | ** ** | **to other**     | ** ** | **from**              | ** ** | **at end** | ** ** |
| ** **                             | ** ** | **of period**  | ** ** | **expenses**                 | ** ** | **accounts (1)** | ** ** | **reserves (2)** | ** ** | **of period** | ** ** |
| ** **                             | ** ** | ** **          | ** ** | ** **                   | ** ** | ** **            | ** ** | ** **            | ** ** | ** ** | ** ** |
| Reserve deducted  from related assets: |       |                |       |                         |       |                  |       |                  |       |   |   |
| Provision for uncollectible accounts:  |       |                |       |                         |       |                  |       |                  |       |   |   |
| 2006                                   |       | $                   | 19,381     |                         | $          | 26,944                |       | $                     | 7,375      |   | $ | 35,285 |   | $ | 18,415 |   |
| 2005                                   |       | $                   | 14,734     |                         | $          | 24,214                |       | $                     | 6,216      |   | $ | 25,783 |   | $ | 19,381 |   |
| 2004                                   |       | $                   | 12,852     |                         | $          | 12,823                |       | $                     | 4,742      |   | $ | 15,683 |   | $ | 14,734 |   |

----

1)              Recoveryof amounts previously written off.

2)                 Principallyuncollectible accounts written off or transferred.

60

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**SIGNATURES**

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

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

** **

**February26, 2007**

Pursuant to therequirements of the Securities Exchange Act of 1934, this report signed belowby the following persons on behalf of the registrant and in the capacities andon 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)                        |                                         |

 

**SUPPLEMENTALINFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THEACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12OF THE ACT**

PSCo has not sent, anddoes not expect to send, an annual report or proxy statement to its securityholder.

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