Table of Contents

 

 

 

**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

# **FORM 10-K**

**(MarkOne)**

 

**x****                ANNUAL REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934**

** **

**For thefiscal year ended December 31, 2009**

** **

**Or**

** **

**o****                   TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934**

** **

**Commissionfile number 001-03280**

 

# **PUBLICSERVICE COMPANY OF COLORADO**

(Exact name of registrant as specified in its charter)

 

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

 

## **1225 17****th**** Street, Denver, Colorado 80202**

(Address of principal executive offices)

 

Registrant’s telephone number, including area code: **303-571-7511**

 

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

 

Securitiesregistered pursuant to section 12(g) of the Act: **None**

 

Indicateby check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act.x Yes o No

 

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

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days. x Yes o No

 

Indicateby check mark whether the registrant has submitted electronically and posted onits corporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 ofthis chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files).  o Yes o No

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulations S-K (§229.405 of this chapter) is not contained herein, and willnot be contained, to the best of the registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. x

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, a non-accelerated filer, or a smaller reportingcompany.  See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act.

 
| o Large  accelerated filer                    |   | oAccelerated  filer          |
|-----------------------------------------------|--------|------------------------------|
|                                          |   |                         |
| x Non-accelerated  filer                      |   | o Smaller  Reporting Company |
| (Do not check if a smaller reporting company) |   |                         |

 

Indicateby check mark whether the registrant is a shell company (as defined in Rule 12b-2of the Act).oYes x No

 

As of March 1,2010, 100 shares of common stock, par value $0.01 per share, were outstanding,all of which were held by Xcel Energy Inc., a Minnesota corporation.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Xcel Energy Inc.’sDefinitive Proxy Statement for its 2010 Annual Meeting of Shareholders isincorporated by reference into Part III of this Form 10-K.

 

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

 

 

 

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**INDEX**

 
| **PART I**                                                                                                                   | 3      |
|-----------------------------------------------------------------------------------------------------------------------------------|--------|
| Item 1 — Business                                                                                                            | 3      |
| DEFINITION OF ABBREVIATIONS  AND INDUSTRY TERMS                                                                                   | 3      |
| COMPANY OVERVIEW                                                                                                                  | 6      |
| ELECTRIC UTILITY OPERATIONS                                                                                                       | 6      |
| Overview                                                                                                                          | 6      |
| Public Utility  Regulation                                                                                                        | 7      |
| Capacity and Demand                                                                                                               | 8      |
| Energy Sources  and Related Transmission Initiatives                                                                              | 8      |
| Fuel Supply and Costs                                                                                                             | 9      |
| Fuel Sources                                                                                                                      | 10     |
| Wholesale  Commodity Marketing Operations                                                                                         | 10     |
| Summary of  Recent Regulatory Developments                                                                                        | 10     |
| Electric Operating  Statistics                                                                                                    | 11     |
| NATURAL GAS UTILITY  OPERATIONS                                                                                                   | 12     |
| Public Utility  Regulation                                                                                                        | 12     |
| Capability and Demand                                                                                                             | 12     |
| Natural Gas Supply and  Costs                                                                                                     | 13     |
| Natural Gas Operating  Statistics                                                                                                 | 13     |
| ENVIRONMENTAL MATTERS                                                                                                             | 14     |
| EMPLOYEES                                                                                                                         | 14     |
| Item 1A — Risk Factors                                                                                                       | 14     |
| Item 1B —  Unresolved Staff Comments                                                                                         | 21     |
| Item 2 — Properties                                                                                                          | 22     |
| Item 3 — Legal Proceedings                                                                                                   | 22     |
| Item 4 — Reserved                                                                                                            | 23     |
|                                                                                                                              |   |
| **PART II**                                                                                                                  | 23     |
| Item 5 —  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities | 23     |
| Item 6 — Selected  Financial Data                                                                                            | 23     |
| Item 7 —  Management’s Discussion and Analysis of Financial Condition and Results of  Operations                        | 23     |
| Item 7A —  Quantitative and Qualitative Disclosures About Market Risk                                                        | 26     |
| Item 8 —  Financial Statements and Supplementary Data                                                                        | 29     |
| Item 9 —  Changes in and Disagreements with Accountants on Accounting and Financial  Disclosure                              | 74     |
| Item 9A —  Controls and Procedures                                                                                      | 74     |
| Item 9B — Other  Information                                                                                                 | 74     |
|                                                                                                                              |   |
| **PART III**                                                                                                                 | 75     |
| Item 10 —  Directors, Executive Officers and Corporate Governance                                                            | 75     |
| Item 11 — Executive  Compensation                                                                                            | 75     |
| Item 12 —  Security Ownership of Certain Beneficial Owners and Management and Related  Stockholder Matters                   | 75     |
| Item 13 —  Certain Relationships and Related Transactions, and Director Independence                                         | 75     |
| Item 14 —  Principal Accountant Fees and Services                                                                            | 75     |
|                                                                                                                              |   |
| **PART IV**                                                                                                                  | 75     |
| Item 15 —  Exhibits and Financial Statement Schedules                                                                        | 75     |
|                                                                                                                              |   |
| **SIGNATURES**                                                                                                                    | 79     |

 

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

 

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**PART I**

 

**Item l**— **Business**

 

# **DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS**

 
| ***Xcel  Energy Subsidiaries and Affiliates***                 | *** *** | *** ***                                                                                                                                                                                                                                                                                                                                                                                                            |
|----------------------------------------------------------------|--------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| NCE                                                            |         | New Century Energies, Inc.                                                                                                                                                                                                                                                                                                                                                                                         |
| NSP-Minnesota                                                  |         | Northern States Power Company, a Minnesota  corporation                                                                                                                                                                                                                                                                                                                                                                 |
| NSP-Wisconsin                                                  |         | Northern States Power Company, a Wisconsin  corporation                                                                                                                                                                                                                                                                                                                                                                 |
| PSCo                                                           |         | Public Service Company of Colorado, a Colorado  corporation                                                                                                                                                                                                                                                                                                                                                             |
| PSRI                                                           |         | P.S.R. Investments, Inc., a manager of  corporate-owned life insurance policies                                                                                                                                                                                                                                                                                                                                    |
| SPS                                                            |         | Southwestern Public Service Company, a New Mexico  corporation                                                                                                                                                                                                                                                                                                                                                          |
| utility  subsidiaries                                          |         | NSP-Minnesota,  NSP-Wisconsin, PSCo, SPS                                                                                                                                                                                                                                                                                                                                                                                |
| WYCO                                                           |         | WYCO  Development L.L.C., a joint venture formed between Xcel Energy and  Colorado Interstate Gas Company to develop  and lease natural gas pipeline, storage, and compression facilities                                                                                                                                                                                                                     |
| Xcel Energy                                                    |         | Xcel Energy Inc., a  Minnesota corporation                                                                                                                                                                                                                                                                                                                                                                              |
| ***Federal  and State Regulatory Agencies***                   | *** *** | *** ***                                                                                                                                                                                                                                                                                                                                                                                                            |
| CAPCD                                                          |         | Colorado Air Pollution  Control Division                                                                                                                                                                                                                                                                                                                                                                                |
| 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; the sale of wholesale electricity, in interstate  commerce, including the sale of electricity at market-based rates;  hydroelectric generation licensing; and accounting requirements for utility  holding companies, service companies, and public utilities. |
| IRS                                                            |         | Internal Revenue  Service                                                                                                                                                                                                                                                                                                                                                                                               |
| NERC                                                           |         | North American Electric  Reliability Corporation.  A  self-regulatory organization, subject to oversight by the U. S. FERC and  government authorities in Canada, to develop and enforce reliability  standards.                                                                                                                                                                                                   |
| SEC                                                            |         | Securities and Exchange  Commission                                                                                                                                                                                                                                                                                                                                                                                     |
| ***Electric,  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.  Allows PSCo to  recover its actual fuel and purchased energy expense in a calendar year to a  benchmark formula.  Short-term sales  margins and margins from the sale of SO2 allowances  are shared with retail customers through the ECA.                                                                                                                  |
| 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.                                                                                                                                                                                                        |

 

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| PCCA                                 |         | Purchased  capacity cost adjustment.  Allows PSCo  to recover from retail customers for all purchased capacity payments to power  suppliers, effective Jan. 1, 2007.   Capacity charges are not included in PSCo’s 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 the  PSCo electric utility provides for bill credits to customers based on  operational performance standards through Dec. 31, 2010.  The QSP for the PSCo natural gas utility  also expires Dec. 31, 2010. |
| RES                                  |         | Renewable energy  standard                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| RESA                                 |         | Renewable energy  standard adjustment                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 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*** | *** *** | *** ***                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| ACES                                 |         | American Clean Energy  and Security Act                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| AFUDC                                |         | Allowance for funds  used during construction.  Defined in  regulatory accounts as 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.   Obligations associated with the retirement of tangible long-lived  assets and the associated asset retirement costs.                                                                                                                                                                                                                                                                                                               |
| ASC                                  |         | FASB Accounting  Standards Codification                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| BACT                                 |         | Best Available Control  Technology                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| BART                                 |         | Best Available Retrofit  Technology                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| CAA                                  |         | Clean Air Act                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| CAMR                                 |         | Clean Air Mercury Rule                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| CO2                                  |         | Carbon dioxide                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| COLI                                 |         | Corporate-owned life  insurance                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Codification                         |         | FASB Accounting  Standards Codification                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| CWIP                                 |         | Construction work in  progress                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| 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  provide 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.                                                                                                                                                                                                                                                                                                                                        |
| FASB                                 |         | Financial Accounting  Standards Board                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| Fitch                                |         | Fitch Ratings                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 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).                                                                                                                                                                                                                                             |
| GHG                                  |         | Greenhouse gas                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| JOA                                  |         | Joint operating  agreement among the utility subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                               |
| LIBOR                                |         | London Interbank  Offered Rate                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| MACT                                 |         | Maximum  Achievable Control Technology                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| mark-to-market                       |         | The  process whereby an asset or liability is recognized at fair value.                                                                                                                                                                                                                                                                                                                                                                                                 |
| MISO                                 |         | Midwest  Independent Transmission System Operator                                                                                                                                                                                                                                                                                                                                                                                                                       |
| Moody’s                         |         | Moody’s  Investor Services                                                                                                                                                                                                                                                                                                                                                                                                                                         |

 

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| 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.                                  |
| NOx                             |         | Nitrogen  oxide                                                                                                                                                                                                                                                      |
| nonutility                      |         | All  items of revenue, expense and investment not associated, either by direct  assignment or by allocation, with providing service to the utility customer.                                                                                                         |
| O&M                         |         | Operating  and maintenance                                                                                                                                                                                                                                           |
| OCI                             |         | Other  comprehensive income                                                                                                                                                                                                                                          |
| 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.                                                                                 |
| PJM                             |         | Pennsylvania-New  Jersey-Maryland Interconnection                                                                                                                                                                                                                    |
| rate base                       |         | The  investor-owned plant facilities for generation, transmission and distribution  and other assets used in supplying utility service to the consumer.                                                                                                              |
| REC                             |         | Renewable  energy credit                                                                                                                                                                                                                                             |
| RFP                             |         | Request  for Proposal                                                                                                                                                                                                                                                |
| ROE                             |         | Return  on equity                                                                                                                                                                                                                                                    |
| RPS                             |         | Renewable  Portfolio Standard, regulation that requires the increased production of  energy from renewable energy sources, such as wind, solar, biomass, and  geothermal.                                                                                       |
| 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. |
| SO2                             |         | Sulfur  dioxide                                                                                                                                                                                                                                                      |
| Standard & Poor’s |         | Standard &  Poor’s Ratings Services                                                                                                                                                                                                                    |
| 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.                     |
| 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.                                                                                              |
| ***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.                                                                                                  |
| GWh                             |         | Gigawatt  hours. One gigawatt hour equals one billion watt hours.                                                                                                                                                                                                    |
| KV                              |         | Kilovolts  (one KV equals one thousand volts)                                                                                                                                                                                                                        |
| KW                              |         | Kilowatts  (one KW equals one thousand watts)                                                                                                                                                                                                                        |
| Kwh                             |         | Kilowatt  hours                                                                                                                                                                                                                                                      |
| MMBtu                           |         | One  million BTUs                                                                                                                                                                                                                                                    |
| MW                              |         | Megawatts  (one MW equals one thousand KW)                                                                                                                                                                                                                           |
| Volt                            |         | The  unit of measurement of electromotive force.   Equivalent to the force required to produce a current of one ampere  through a resistance of one ohm.  The  unit of measure for electrical potential.   Generally measured in kilovolts.           |
| Watt                            |         | A  measure of power production or usage.                                                                                                                                                                                                                             |

 

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**COMPANYOVERVIEW**

 

PSCo was incorporated in 1924 under the laws ofColorado.  PSCo is an operating utilityengaged primarily in the generation, purchase, transmission, distribution andsale of electricity in Colorado.  Thewholesale customers served by PSCo comprised approximately 20 percent of itstotal sales in 2009.  PSCo also purchases,transports, distributes and sells natural gas to retail customers and transportscustomer-owned natural gas.  PSCoprovides electric utility service to approximately 1.4 million customers andnatural gas utility service to approximately 1.3 million customers.  All of PSCo’s retail electric operatingrevenues were derived from operations in Colorado during 2009.  Generally, PSCo’s earnings range fromapproximately 45 percent to 55 percent of Xcel Energy’s consolidated netincome.

 

PSCo owns the followingdirect subsidiaries:  1480 Welton, Inc.,and United Water Company, both of which own certain real estate interests forPSCo; and Green and Clear Lakes Company, which owns water rights.  PSCo also owns PSRI, which held certainformer employees’ life insurance policies. Following settlement with the IRS during 2007, such policies wereterminated.  PSCo also holds acontrolling interest in several other relatively small ditch and watercompanies.

 

PSCo conducts its utilitybusiness in the following reportable segments: regulated electric utility,regulated natural gas utility and all other. Comparative segment revenues and related financial information forfiscal 2009, 2008 and 2007 are set forth in Note 17 to the accompanyingconsolidated financial statements.

 

PSCo focuses on growingthrough investments in electric and natural gas rate base to meet growingcustomer demands, environmental and renewable energy initiatives and tomaintain or increase reliability and quality of service to customers.  PSCo files periodic rate cases, establishesformula rate or automatic rate adjustment mechanisms with state and federalregulators to earn a return on its investment and recover costs of operations.

 

**ELECTRIC UTILITY OPERATIONS**

** **

**Overview**

** **

***Climate Change and CleanEnergy***—***Like most other utilities,PSCo is subject to a significant array of environmental regulations.  Further, there are significant futureenvironmental regulations under consideration to encourage the use of cleanenergy technologies and regulate emissions of GHGs to address c*****limate change. **PSCo is subject tostate RPS requirements which we believe they will be in a position to achieveby the applicable state deadlines. Although the exact form and design of any federal RPS policy isuncertain at this time, we believe that we will be well-positioned to meet afederal standard as well, although the ultimate design of any federal policycould have a varied impact on PSCo depending upon the energy efficiency andother standards imposed.  In addition,PSCo’s electric generating facilities have been and are likely to be furthersubject to climate change legislation introduced at either the state or federallevel within the next few years.  In2009, the EPA took a number of steps toward the regulation of GHGs under theCAA.  By spring 2010, the EPA expects topromulgate regulations to control GHGs from mobile sources.  Thereafter, the EPA anticipates phasing-inpermit requirements and regulation of GHGs for large stationary sources, suchas power plants, in calendar year 2011.

 

While PSCo is notcurrently subject to state or federal limits on its GHG emissions, PSCo hasundertaken a number of initiatives to prepare for climate change regulation andreduce our GHG emissions.  Theseinitiatives include emission reduction programs, energy efficiency and conservationprograms, renewable energy development and technology explorationprojects.  Although the impact of climatechange policy on PSCo will depend on the specifics of state and federalpolicies, legislation and regulation, PSCo believes that, based on prior statecommission practice, PSCo would be granted the authority to recover the cost ofthese initiatives through rates.

 

***Utility Restructuring and Retail Competition***— The FERC has continued with its effortsto promote more competitive wholesale markets through open-access transmission andother means.  As a consequence, PSCo andits wholesale customers can purchase from competing wholesale suppliers and usethe transmission systems of the utility subsidiaries on a comparable basis tothe utility subsidiaries to serve their native load.  PSCo supports the continued development ofwholesale competition and non-discriminatory wholesale open access transmissionservices.  The FERC has approved the openaccess transmission planning processes for the PSCo.  PSCo is pursuing upgrades to its transmissionsystem and the systems of neighboring utilities in order to facilitaterenewable energy expansion, in response to statutory changes enacted in 2007.

 

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The retail electricbusiness faces competition as industrial and large commercial customers havesome ability to own or operate facilities to generate their ownelectricity.  In addition, customers mayhave the option of substituting other fuels, such as natural gas orsteam/chilled water for heating, cooling and manufacturing purposes, or theoption of relocating their facilities to a lower cost region.  While PSCo faces these challenges, its ratesare competitive with currently available alternatives.

 

**Public Utility Regulation**

** **

***Summary of Regulatory Agencies and Areas ofJurisdiction *****—** PSCo is regulated by the CPUC with respect to itsfacilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect toits wholesale electric operations, accounting practices, hydroelectriclicensing, wholesale sales for resale, the transmission of electricity ininterstate commerce and certain natural gas transaction in interstatecommerce.  PSCo has receivedauthorization from the FERC to make wholesale electricity sales at market-basedprices; however, PSCo withdrew its market-based rate authority with respect tosales in its own and affiliated operating company control areas.

 

***Fuel, Purchased Energy and ConservationCost-Recovery Mechanisms *****—** PSCo hasseveral retail adjustment clauses that recover fuel, purchased energy and otherresource costs:

 

·                     *ECA* — The ECArecovers fuel and purchase power costs.  Short-term sales margins and margins fromthe sale of SO2 allowances are shared with retail customersthrough the ECA.  The totalincentive cannot exceed $11.25 million in any year.  For 2009, it included an incentive adjustmentto encourage efficient operation of base load coal plants and to encourage costreductions through purchases of economical short-term energy.  Effective Jan. 1, 2010, the incentiveadjustment was eliminated from the ECA mechanism.  The ECA mechanism is revised quarterly.

·                     *PCCA* — ThePCCA allows for recovery of purchased capacity payments for most power purchaseagreements.  New rates went into effect Jan. 1,2010.

·                     *SCA* — The SCA allows PSCo to recoverthe difference between its actual cost of fuel and the amount of these costsrecovered under its base steam service rates. The SCA rate is revised annually on Jan. 1, as well as on aninterim basis to coincide with changes in fuel costs.

·                     *AQIR* —Effective January 2003, the AQIR recovers, over a 15-year period, theincremental cost (including fuel and purchased energy) incurred by PSCo as aresult of a voluntary plan to reduce emissions and improve air quality in theDenver metro area.  The CPUC approvedPSCo’s filing to roll the AQIR into base rates, which was reflected in rates onJan. 1, 2010.

·                     *DSMCA* — TheDSMCA clause permits PSCo to recover DSM and interruptible service optioncredit (ISOC) costs on a concurrent basis and performance initiatives based onachieving various energy savings goals. The CPUC approved recovery of the full amount of DSM-related coststhrough the combination of base rates and a tracker mechanism in the DSMCAstarting in 2010.

·                     *RESA* — The RESA recovers the incrementalcosts of compliance with the RES and is set at its maximum level of2 percent of the customer’s total bill.

·                     *WindEnergy Service* — Is a premium service, for those customerswho voluntarily choose to contribute funds for the acquisition of additionalrenewable resources beyond the level of PSCo’s resource plan.  Wind Energy Service customers pay a charge thatis in addition to the rates paid by other customers.  The service is marketed as WindSource®.

·                     *Transmission CostAdjustment (TCA) *— Effective January 2008, the TCA provides for the recoveryoutside of rate cases of transmission plant revenue requirements and allows fora return on construction work in progress for transmission investments.

 

PSCorecovers fuel and purchased energy costs from its wholesale electric customersthrough a fuel cost adjustment clause accepted for filing by the FERC.  PSCo’s larger wholesale customers have agreedto pay the full cost of the acquisition of certain non-solar renewable energypurchase and generation costs through a rider and in exchange receive renewableenergy credits associated with those resources.

 

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***Performance-Based Regulation Plan (PBRP)and Quality of Service Requirements *****—** PSCo currentlyoperates under an electric and natural gas PBRP.  The major components of this regulatory planinclude:

 

·                     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

·                     A natural gas QSP thatprovides for bill credits to customers if PSCo does not achieve certainperformance targets relating to natural gas leak repair time and customerservice through 2010.

 

PSCoregularly monitors and records as necessary an estimated customer refundobligation under the PBRP.  In April ofeach year following the measurement period, PSCo files its proposed rateadjustment under the PBRP.  The CPUCconducts proceedings to review and approve these rate adjustments annually.

 

**Capacity and Demand**

** **

The uninterrupted system peak demand for PSCo’selectric utility for each of the last three years and the forecast for 2010,assuming normal weather, is listed below.

 
| **System  Peak Demand (in MW)** | ** ** |
|---------------------------------|------------|
| **2007**                        | ** ** | **2008** | ** ** | **2009** | ** ** | **2010  Forecast** | ** ** |
| 6,950                           |       | 6,903 |   | 6,258 |   | 6,608 |   |

 

The peak demand for PSCo’ssystem typically occurs in the summer. The 2009 uninterrupted system peak demand for PSCo occurred on Aug. 12,2009.

 

**EnergySources and Related Transmission Initiatives**

 

PSCo expects to meet itssystem capacity requirements through existing power plants, power purchases,new generation facilities, DSM options and phased expansion of existinggeneration at select power plants.

 

***Purchased Transmission Services****** —***In additionto using its own transmission system, PSCo has contracts with regionaltransmission service providers to deliver power and energy to PSCo’s customers***.***

 

***Purchased Power***— PSCo has contracts to purchase power from otherutilities and independent power producers. Capacity is the measure of the rate at which a particular generatingsource produces electricity.  Energy is ameasure of the amount of electricity produced from a particular generatingsource over a period of time.  Long-termpurchase power contracts typically require a periodic payment to secure thecapacity from a particular generating source and a charge for the associatedenergy actually purchased.

 

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 and for variousother operating requirements.

 

***PSCo Resource Plan ***— In September 2008, the CPUC issued its orderdetailing the amount of resources that will be added, including the following:

 

·                     Increase in windportfolio of 850 MW by 2015. PSCo would then have a total of approximately 1,900 MW of wind powerresources;

·                     Addup to250 MW of concentrating solar thermal technology with thermal storage;

·                     Increase customer efficiency andconservation programs with plans to meet the CPUC goals of annual energysales reductions to approximately 3,669 GWH, that would yield ademand savings in the range of 886 MW to 994 MW by 2020;

·                     Retirement of two older coal-burningplants (two units at Arapahoe and two units at Cameo), replacing the capacitywith company owned resources, provided the costs are reasonable; and

·                     Reduce PSCo’s CO2 emissions by 10 and 15 percent below2005 levels and for PSCo to propose additional reductions to achieve a 20percent reduction by 2020 in its next plan.

 

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PSCoacquired 174 MW of wind resources and 19 MW of central station photovoltaic(PV) solar resources through separate RFPs and those contracts werespecifically approved by the CPUC.  In January 2009,PSCo issued an all-source RFPs to fill the approved resource plan.  Bids were received in April 2009, andPSCo filed its bid evaluation report with the CPUC in August 2009.

 

In October 2009, theCPUC approved the acquisitions of the resources identified in the evaluationreport.  With minor modification, theCPUC adopted PSCo’s preferred plan which includes an incremental 900 MW ofadditional intermittent renewable energy resources (wind and PV solar) andapproximately 280 MW of “new technology” renewable energy sources.  The CPUC approved the negotiation ofpurchased power contracts from a pool of PV solar bidders, rather thandesignating certain bidders.  The CPUC approved the selection ofabout 800 MW of traditional gas-fired resources.  The CPUC preferred that PSCo file its nextresource plan in the normal course of business in the fall of 2011 rather thanmaking an interim filing in 2010.

 

***RES —*** The 2007Colorado legislature adopted an increased RES that requires PSCo to generate orcause to be generated electricity from renewable resources equaling:

 

·                     At least 10 percent ofits retail sales for the years 2011 through 2014;

·                     15 percent of retailsales for the years 2015 through 2019;

·                     20 percent of retailsales by 2020 and after; and

·                     4 percent must be generatedfrom solar renewable resources with half the solar resources being located atcustomers’ facilities.

 

Thelaw limits the net incremental retail rate impact from these renewable resourceacquisitions as compared to non-renewable resources to 2 percent.  The new legislation encourages the CPUC toconsider earlier and timely cost-recovery for utility investment in renewableresources, including the use of a forward rider mechanism.

 

TheCPUC approved all material aspects of PSCo’s 2009 RES compliance plan in August 2009.  The 2010 compliance plan was filed in October 2009.

 

***San Luis Valley-Calumet-Comanche Unit 3 TransmissionProject******—*** PSCo and Tri-State Generation andTransmission Association filed a joint application with the CPUC for acertificate of need and public convenience in May 2009.  Theproject consists of four components of both 230 KV and 345 KV line andsubstation construction.  The line isintended to assist in bringing solar power in the San Luis Valley to load.  The line is expected to be placed in-servicein 2013 if no significant issues in the siting and permitting of the line areencountered.  Several landowners are opposing thistransmission line, including two large ranches. Hearings before an ALJ were conducted in February 2010 with adecision pending.

** **

**FuelSupply and Costs**

** **

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

 

 
| ** ** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **  | ** ** | ** **  | ** ** | **Weighted**       | ** ** |
|------------|------------|------------|------------|------------------|------------|-------------|------------|-------------|------------|--------------------|------------|
| ** ** | ** ** | **Coal**   | ** ** | **Natural  Gas** | ** ** | **Average** | ** ** |
| ** ** | ** ** | **Cost**   | ** ** | **Percent**      | ** ** | **Cost**    | ** ** | **Percent** | ** ** | **Fuel Cost** | ** ** |
| 2009       |       | $          | 1.52       |             | 82         | %           | $          | 3.99        |       | 18                 | %          | $ | 1.97 |   |
| 2008       |       | 1.42       |       | 84               |       | 7.03        |       | 16          |       | 2.31               |       |
| 2007       |       | 1.26       |       | 84               |       | 4.34        |       | 16          |       | 1.76               |       |
|            |            |            |            |                  |            |             |            |             |            |                    |            |  |  |  |

 

See additional discussionof fuel supply and costs under Item 1A — Risk Factors.

 

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**FuelSources**

 

*Coal** *****—**Coal inventory levels may vary widely amongplants.  However, PSCo normally maintainsapproximately 41 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2009and 2008 were approximately 68 and 32 days usage, respectively, based onthe maximum burn rate for all of PSCo’s coal-fired plants.  PSCo’s generation stations use low-sulfurwestern coal purchased primarily under contracts with suppliers operating inColorado and Wyoming.  During 2009 and2008, PSCo’s coal requirements for existing plants were approximately 9.2million and 11 million tons, respectively.

 

PSCohas contracted for coal suppliers to supply 82 percent of its coalrequirements in 2010, 50 percent of its coal requirements in 2011 and19 percent of its coal requirements in 2012.  Any remaining requirements will be filledthrough an RFP process or through over-the-counter transactions.

 

PSCohas coal transportation contracts that provide for delivery of 95 percentof its coal requirements in 2010, 95 percent of its coal requirements in2011 and 60 percent of its coal requirements in 2012.  Coal delivery may be subject to short-terminterruptions or reductions due to operation of the mines, transportationproblems, weather, and availability of equipment.

 

*Natural gas** *****—**PSCo uses both firm and interruptible natural gasand standby oil in combustion turbines and certain boilers.  Natural gas supplies for PSCo’s power plantsare procured under contracts to provide an adequate supply of fuel.  The supply contracts expire in various yearsfrom 2010 through 2020.  Thetransportation and storage contracts expire in various years from 2010 to2040.  Certain natural gas supply andtransportation agreements include obligations for the purchase and/or deliveryof specified volumes of natural gas or to make payments in lieu ofdelivery.  At Dec. 31, 2009, PSCo’scommitments related to supply contracts were approximately $159 millionand transportation and storage contracts were approximately $1.1 billion.

 

**WholesaleCommodity Marketing Operations**

 

PSCo conducts variouswholesale marketing operations, including the purchase and sale of electriccapacity, energy and energy related products. PSCo uses physical and financial instruments to reduce commodity priceand credit risk and hedge supplies and purchases.  See additional discussion under Item 7A —Quantitative and Qualitative Disclosures about Market Risk.

 

**Summary of Recent FederalRegulatory Developments**

** **

TheFERC has jurisdiction over rates for electric transmission service ininterstate commerce and electricity sold at wholesale, hydro facilitylicensing, natural gas transportation, accounting practices, and certain otheractivities of Xcel Energy’s utility subsidiaries, including enforcement of NERCmandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s utilityactivities, including regulation of retail rates and environmentalmatters.  In addition to the mattersdiscussed below, see Note 14 to the consolidated financial statements for adiscussion of other regulatory matters.

 

***FERC Rules Implementing Energy Policy Act of 2005(Energy Act) *****—** The Energy Act required the FERC to adopt newregulations to implement various aspects of the Energy Act.  Violations of FERC rules are potentiallysubject to enforcement action by the FERC including financial penalties up to$1 million per day per violation.

 

While PSCo cannot predictthe ultimate impact the new regulations will have on its operations orfinancial results, PSCo is taking actions that are intended to comply with andimplement new FERC rules and regulations as they become effective.

 

***Electric Reliability StandardsMatters*****—**In 2008,PSCo was subject to an audit of its compliance with the NERC and regionalreliability standards by the Western Electricity Coordinating Council (WECC),the NERC regional entity for the PSCo system. On Oct. 31, 2008, the WECC auditors issued their final audit reporton PSCo’s compliance with electric reliability standards.  The report found a possible violation of onereliability standard related to relay maintenance.

 

In2008, PSCo filed self-reports with the WECC relating to failure to completecertain generation station battery tests, relay maintenance intervals andrecord keeping associated with certain critical infrastructure protectionstandards.  In 2009, PSCo reachedagreement with the WECC that would resolve the open 2008 audit finding and the2008 self reports by payment of a non-material penalty.  PSCo is in the process of developing adefinitive settlement agreement.  Thissettlement agreement will be subject to NERC and FERC approval.

 

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***Electric Transmission RateRegulation***** —**The FERCregulates the rates charged and terms and conditions for electric transmissionservices.  FERC policy encouragesutilities to turn over the functional control of their electric transmissionassets for the sale of electric transmission services to an RTO.  Each RTO separately files regionaltransmission tariff rates for approval by the FERC.  All members within that RTO are thensubjected to those rates.  In 2009, PSCofiled a tariff to participate with other utilities in WestConnect, a consortiumof utilities offering regionalized non-firm transmission services.  The WestConnect tariff was effective in thefirst quarter of 2009.  The WestConnecttariff has not had a material impact on PSCo transmission usage orrevenues.  WestConnect may providewholesale energy market functions in the future, but would not be an RTO.

*** ***

***Market Based Rate Rules *****—** Each of the Xcel Energy utility subsidiaries has been grantedmarket-based rate authority.  Undermarket based rules, PSCo will be required to file for such reauthorization in June 2010.  Presently the Xcel Energy utilitysubsidiaries may not sell power at market-based rates within the PSCo balancingauthorities, where they have been found to have market power under the FERC’sapplicable analysis.  PSCo has cost-basedcoordination tariffs that it may use to make sales in its balancingauthorities.

*** ***

***FERC Tie Line Investigation —***In October 2007, the FERC Office ofEnforcement, DOI, commenced a non-public investigation of use of networktransmission service across the Lamar Tie Line, a transmission facility thatconnects PSCo and SPS.  In July 2008,the DOI issued a preliminary report alleging Xcel Energy violated certain FERCpolicies and rules and approved tariffs. The report represents the preliminary conclusions of the DOI and issubject to additional procedures.  Thereport does not constitute a finding by the FERC, which may, accept, modify orreject any or all of the preliminary conclusions in the report.  Xcel Energy disagrees with the preliminaryreport.  Xcel Energy continues tocooperate with the DOI investigation. Given the preliminary nature of this matter, Xcel Energy is unable todetermine if the resolution of this matter will have a material adverse impacton operations, cash flows or financial condition.

** **

**Electric Operating Statistics**

 
| ** **                                    | ** ** | **Year  Ended Dec. 31,** | ** ** |
|-----------------------------------------------|------------|-------------------------------|------------|
| ** **                                    | ** ** | **2009**                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Electric  sales (millions of Kwh)**         | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential                                   |       | 8,715                         |       | 8,905 |   | 8,904 |   |
| Commercial and  industrial                    |       | 18,448                        |       | 19,137 |   | 18,947 |   |
| Public authorities and  other                 |       | 226                           |       | 229 |   | 235 |   |
| **Total retail**                              |       | 27,389                        |       | 28,271 |   | 28,086 |   |
| Sales for resale                              |       | 6,949                         |       | 7,756 |   | 8,913 |   |
| **Total energy sold**                         |       | 34,338                        |       | 36,027 |   | 36,999 |   |
|                                          |       |                          |       |   |   |   |   |
| **Number  of customers at end of period**     |       |                          |       |   |   |   |   |
| Residential                                   |       | 1,150,181                     |       | 1,142,106 |   | 1,126,019 |   |
| Commercial and  industrial                    |       | 151,637                       |       | 150,826 |   | 149,179 |   |
| Public authorities and  other                 |       | 58,371                        |       | 58,195 |   | 58,559 |   |
| **Total retail**                              |       | 1,360,189                     |       | 1,351,127 |   | 1,333,757 |   |
| Wholesale                                     |       | 30                            |       | 35 |   | 51 |   |
| **Total customers**                           |       | 1,360,219                     |       | 1,351,162 |   | 1,333,808 |   |
|                                          |       |                          |       |   |   |   |   |
| **Electric  revenues (thousands of dollars)** |       |                          |       |   |   |   |   |
| Residential                                   |       | $                             | 862,242    |   | $ | 914,531 |   | $ | 801,162 |   |
| Commercial and  industrial                    |       | 1,309,770                     |       | 1,514,652 |   | 1,266,800 |   |
| Public authorities and  other                 |       | 44,434                        |       | 44,066 |   | 41,426 |   |
| **Total retail**                              |       | 2,216,446                     |       | 2,473,249 |   | 2,109,388 |   |
| Wholesale                                     |       | 349,909                       |       | 457,623 |   | 438,120 |   |
| Other electric revenues                       |       | 112,223                       |       | 52,057 |   | 57,880 |   |
| **Total electric revenues**                   |       | $                             | 2,678,578  |   | $ | 2,982,929 |   | $ | 2,605,388 |   |
|                                          |       |                          |       |   |   |   |   |
| Kwh sales per retail  customer                |       | 20,136                        |       | 20,924 |   | 21,058 |   |
| Revenue per retail  customer                  |       | $                             | 1,630      |   | $ | 1,831 |   | $ | 1,582 |   |
| Residential revenue per  Kwh                  |       | 9.89                          | ¢     | 10.27 | ¢ | 9.00 | ¢ |
| Commercial and  industrial revenue per Kwh    |       | 7.10                          |       | 7.91 |   | 6.69 |   |
| Wholesale revenue per  Kwh                    |       | 5.04                          |       | 5.90 |   | 4.92 |   |

 

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**NATURAL GAS UTILITY OPERATIONS**

** **

The most significantrecent developments in the natural gas operations of PSCo are continuedvolatility in natural gas market prices and the continued trend of declininguse per residential customer, as well as small commercial and industrial customers(C&I), as a result of improved building construction technologies, higherappliance efficiencies, and conservation. From 1999 to 2009, average annual sales to the typical PSCo residentialcustomer declined from 96 MMBtu per year to 80 MMBtu per year, and to a typicalsmall C&I customer declined from 463 MMBtu per year to 396 MMBtu per yearon a weather-normalized basis.  Althoughwholesale price increases do not directly affect earnings because of naturalgas cost recovery mechanisms, high prices can encourage further efficiencyefforts by customers.

 

**PublicUtility Regulation**

** **

***Summary of Regulatory Agencies and Areas ofJurisdiction***** —**PSCo isregulated by the CPUC with respect to its facilities, rates, accounts, servicesand issuance of securities.  PSCo holds aFERC certificate that allows it to transport natural gas in interstate commercewithout PSCo becoming subject to full FERC jurisdiction under the federalNatural Gas Act.  PSCo is also subject tothe jurisdiction of the FERC with respect to certain natural gas transactionsin interstate commerce.

 

***Purchased Gas and ConservationCost-Recovery Mechanisms***** —**PSCo has tworetail adjustment clauses that recover purchased gas and other resource costs:

 

·                     *GCA* — The GCAmechanism allows PSCo to recover its actual costs of purchased gas andtransportation to meet the requirements of its customers.  The GCA is revised quarterly to allow forchanges in gas rates.

·                     *DSMCA* — PSCohas a low-income energy assistance program. The costs of this energy conservation and weatherization program arerecovered through the gas DSMCA.

 

***Performance-Based Regulation and Quality ofService Requirements***** —**The CPUCestablished a combined electric and natural gas QSP.  See further discussion under Item 1—Electric Utility Operations.

 

For a further discussionof rate and regulatory matters see Note 14 to the consolidated financialstatements.

 

**Capability and Demand**

** **

**PSCoprojects peak day natural gas supply requirements for firm sales and backuptransportation, which include transportation customers contracting for firmsupply backup, to be 1,897,604 MMBtu.  Inaddition, firm transportation customers hold 574,910 MMBtu of capacity for PSCowithout supply backup.  Total firmdelivery obligation for PSCo is 2,472,514 MMBtu per day.  The maximum daily deliveries for PSCo in 2009for firm and interruptible services were 1,873,412 MMBtu on Dec. 8, 2009.**

** **

PSCo purchases natural gasfrom independent suppliers.  Thesepurchases are generally priced based on market indices that reflect currentprices.  The natural gas is deliveredunder transportation agreements with interstate pipelines.  These agreements provide for firm deliverablepipeline capacity of approximately 1,829,862 MMBtu per day, which includes834,277 MMBtu of supplies held under third-party underground storageagreements.  During 2009, a capacityrelease contract of 30,000 MMBtu per day of firm pipeline capacity expired, andanother 33,850 MMBtu per day was released to PSCo electric operations,resulting in a net reduction of 63,850 MMBtu per day in pipeline capacity.  Also during 2009, 165,521 MMBtu of storagecapacity was converted to firm transportation with balancing serviceattached.  In addition, PSCo operatesthree company-owned underground storage facilities, which provide about 41,000MMBtu 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.

 

PSCois required by CPUC regulations to file a natural gas purchase plan by June ofeach year projecting and describing the quantities of natural gas supplies,upstream services and the costs of those supplies and services for the 12-monthperiod of the following year.  PSCo isalso required to file a natural gas purchase report by October ofeach year reporting actual quantities and costs incurred for natural gassupplies and upstream services for the previous 12-month period.

 

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**Natural Gas Supply and Costs**

 

PSCoactively seeks natural gas supply, transportation and storage alternatives toyield a diversified 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 following tablesummarizes the average delivered cost per MMBtu of natural gas purchased forresale by PSCo’s regulated retail natural gas distribution business:

 
| 2009 |   | $    | 5.13   |   |
|------|--------|------|--------|--------|
| 2008 |   | 7.04 |   |
| 2007 |   | 5.87 |   |

 

PSCo has natural gas supply,transportation and storage agreements that include obligations for the purchaseand/or delivery of specified volumes of natural gas or to make payments in lieuof delivery.  At Dec. 31, 2009, PSCowas committed to approximately $1.5 billion in such obligations underthese contracts, which expire in various years from 2010 through 2029.

 

PSCopurchases natural gas by optimizing a balance of long-term and short-termnatural gas purchases, firm transportation and natural gas storagecontracts.  During 2009, PSCo purchasednatural gas from approximately 38 suppliers.

 

**Natural Gas OperatingStatistics**

 
| ** **                                      | ** ** | **Year  Ended Dec. 31,** | ** ** |
|-------------------------------------------------|------------|-------------------------------|------------|
| ** **                                      | ** ** | **2009**                      | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Natural gas deliveries (thousands of MMBtu)** |       | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Residential                                     |       | 95,566                        |       | 96,871 |   | 93,664 |   |
| Commercial  and industrial                      |       | 39,878                        |       | 41,121 |   | 40,216 |   |
| **Total retail**                                |       | 135,444                       |       | 137,992 |   | 133,880 |   |
| Transportation  and other                       |       | 109,906                       |       | 115,923 |   | 117,240 |   |
| **Total deliveries**                            |       | 245,350                       |       | 253,915 |   | 251,120 |   |
|                                            |       |                          |       |   |   |   |   |
| **Number of customers at end of period**        |       |                          |       |   |   |   |   |
| Residential                                     |       | 1,193,418                     |       | 1,186,255 |   | 1,169,306 |   |
| Commercial  and industrial                      |       | 99,654                        |       | 99,425 |   | 98,053 |   |
| **Total retail**                                |       | 1,293,072                     |       | 1,285,680 |   | 1,267,359 |   |
| Transportation  and other                       |       | 4,789                         |       | 4,313 |   | 4,110 |   |
| **Total customers**                             |       | 1,297,861                     |       | 1,289,993 |   | 1,271,469 |   |
|                                            |       |                          |       |   |   |   |   |
| **Natural gas revenues (thousands of dollars)** |       |                          |       |   |   |   |   |
| Residential                                     |       | $                             | 745,728    |   | $ | 941,077 |   | $ | 808,738 |   |
| Commercial  and industrial                      |       | 285,199                       |       | 368,143 |   | 313,805 |   |
| **Total retail**                                |       | 1,030,927                     |       | 1,309,220 |   | 1,122,543 |   |
| Transportation  and other                       |       | 63,032                        |       | 64,512 |   | 63,563 |   |
| **Total natural gas revenues**                  |       | $                             | 1,093,959  |   | $ | 1,373,732 |   | $ | 1,186,106 |   |
|                                            |       |                          |       |   |   |   |   |
| MMBtu  sales per retail customer                |       | 104.75                        |       | 107.33 |   | 105.64 |   |
| Revenue  per retail customer                    |       | $                             | 797        |   | $ | 1,018 |   | $ | 886 |   |
| Residential  revenue per MMBtu                  |       | 7.80                          | ¢     | 9.71 | ¢ | 8.63 | ¢ |
| Commercial  and industrial revenue per MMBtu    |       | 7.15                          |       | 8.95 |   | 7.80 |   |
| Transportation  and other revenue per MMBtu     |       | 0.57                          |       | 0.56 |   | 0.54 |   |

 

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**ENVIRONMENTAL MATTERS**

** **

PSCo’sfacilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over airemissions, water quality, wastewater discharges, solid wastes and hazardoussubstances.  Various company activitiesrequire registrations, permits, licenses, inspections and approvals from theseagencies.  PSCo has received allnecessary authorizations for the construction and continued operation of itsgeneration, transmission and distribution systems.  PSCo facilities have been designed andconstructed to operate in compliance with applicable environmental standards.

 

PSCostrives to comply with all environmental regulations applicable to itsoperations.  However, it is not possibleto determine when or to what extent additional facilities or modifications ofexisting or planned facilities will be required as a result of changes toenvironmental regulations, interpretations or enforcement policies or, whateffect future laws or regulations may have upon PSCo’s operations.  For more information on environmentalcontingencies, see Note 15 to the consolidated financial statements.

 

**EMPLOYEES**

** **

Thenumber of full-time PSCo employees at Dec. 31, 2009 and 2008 was 2,791 and2,772, respectively.  Of these full-timeemployees, 2,124, or 76 percent, and 2,159,or 78 percent, respectively,are covered under collective bargaining agreements.  See Note 9 to the consolidated financialstatements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., asubsidiary of Xcel Energy, also provide services to PSCo and are not consideredin the above amounts.

 

**Item 1A — Risk Factors**

** **

**Oversight of Risk and Related Processes**

** **

The goal of Xcel Energy’srisk management process, which includes PSCo, is to understand and managematerial risk; management is responsible for identifying and managing therisks, while directors oversee and hold management accountable.  Our risk management process has three parts:identification and analysis, management and mitigation, and communication anddisclosure.  

 

Our management identifiesand analyzes risks to determine materiality and other attributes like timing,probability and controllability. Management broadly considers our business, the utility industry, thedomestic and global economy, and the environment to identify risks.  Identification and analysis occurs formallythrough a key risk assessment process conducted by senior management, thesecurities disclosure process, the hazard risk management process, and internalauditing and compliance with financial and operational controls.  Management also identifies and analyzes riskthrough its business planning process and development of goals and keyperformance indicators, which include risk identification to determine barriersto implementing our strategy.  At thesame time, the business planning process identifies areas where a business areamay take inappropriate risk to meet goals.

 

Thegoal of the risk management process is to mitigate the risks inherent in theimplementation of Xcel Energy’s and PSCo’s strategy.  The process for risk management andmitigation includes our code of conduct and other compliance policies, formalstructures and groups, and overall business management.  At a threshold level, we have developed arobust compliance program and promote a culture of compliance, which mitigatesrisk.  In addition to the code ofconduct, we have a robust compliance program, including policies, training andreporting options.  

 

Buildingon the culture of compliance, we manage and mitigate risks through formalstructures and groups, including management councils, risk committees, and theservices of corporate areas such as internal audit, the corporate controllerand legal services.  While we havedeveloped a number of formal structures for risk management, many materialrisks affect the business as a whole and are managed across business areas. 

 

Weconfront legislative and regulatory policy and compliance risks, includingrisks related to climate change and emission of CO2 and risks forrecovery of capital and operating costs; resource planning and other long-termplanning risks, including resource acquisition risks; financial risks,including credit, interest rate and capital market risks; and macroeconomicrisks, including risks related to economic conditions and changes in demand forour products and services.  Cross-cuttingrisks such as these are discussed and managed across business areas andcoordinated by Xcel Energy’s and PSCo’s senior management.

 

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Management providesinformation to the Xcel Energy’s Board in presentations and communications overthe course of the Board calendar.  Seniormanagement presents an assessment of key risks to the Board annually.  The presentation of the key risks and thediscussion provides the Board with information on the risks management believesare material, including the earnings impact, timing, likelihood andcontrollability.  Based on thispresentation, the Board reviews risks at an enterprise level and confirms riskmanagement and mitigation are included in Xcel Energy’s and PSCo’sstrategy.  

 

The guidelines oncorporate governance and committee charters define the scope of review andinquiry for the Board and committees. The standing committees also oversee risk management as part of theircharters.  Each committee hasresponsibility for overseeing aspects of risk and our management and mitigationof the risk.  The Xcel Energy Board hasoverall responsibility for risk oversight. As described above, the Board reviews the key risk assessment processpresented by senior management.  This keyrisk assessment analyzes the most likely areas of future risk to XcelEnergy.  The Xcel Energy Board alsoreviews the performance and annual goals of each business area.  This review, when combined with the oversightof specific risks by the committees, allows the Board to confirm risk isconsidered in the development of goals and that risk has been adequatelyconsidered and mitigated in the execution of corporate strategy.

** **

**Risks Associated with OurBusiness**

** **

***Our profitability dependsin part on our ability to recover costs from our customers and there may bechanges in circumstances or in the regulatory environment that impair ourability to recover costs from our customers.***

 

We are subject tocomprehensive regulation by federal and state utility regulatory agencies.  The state utility commission regulates manyaspects of our utility operations, including siting and construction offacilities, customer service and the rates that we can charge customers.  The FERC has jurisdiction, among otherthings, over wholesale rates for electric transmission service, the sale ofelectric energy in interstate commerce and certain natural gas transactions ininterstate commerce.

 

Our profitability isdependent on our ability to recover the costs of providing energy and utilityservices to our customers and earn a return on our capital investment in ourutility operations.  We currently provideservice at rates approved by one or more regulatory commissions.  These rates are generally regulated based onan analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge mayor may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunityto earn a reasonable rate of return on invested capital, there can be noassurance that the applicable regulatory commission will judge all of our coststo have been prudently incurred or that the regulatory process in which ratesare determined will always result in rates that will produce full recovery ofour costs.  Rising fuel costs couldincrease the risk that we will not be able to fully recover our fuel costs fromour customers.  Furthermore, there couldbe changes in the regulatory environment that would impair our ability torecover costs historically collected from our customers.  If all of our costs are not recovered throughcustomer rates, we could incur financial operating losses, which, over the longterm, could jeopardize our ability to meet our financial obligations.

 

Management currentlybelieves these prudently incurred costs are recoverable given the existingregulatory mechanisms in place.  However,changes in regulations or the imposition of additional regulations, includingadditional environmental regulation or regulation related to climate change,could have an adverse impact on our results of operations and hence couldmaterially and adversely affect our ability to meet our financial obligations,including debt payments.

 

***Any reductions in ourcredit ratings could increase our financing costs and the cost of maintainingcertain contractual relationships.***

*** ***

We cannot be assured thatany of our current ratings will remain in effect for any given period of timeor that a rating will not be lowered or withdrawn entirely by a ratingagency.  In addition, our credit ratings maychange as a result of the differing methodologies or change in themethodologies used by the various rating agencies.  For example, Standard & Poor’scalculates an imputed debt associated with capacity payments from purchasepower contracts.  An increase in theoverall level of capacity payments would increase the amount of imputed debt,based on Standard & Poor’s methodology.  Therefore, our credit ratings could beadversely affected based on the level of capacity payments associated withpurchase power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowingcosts.

 

***We are subject tointerest rate risk.***

*** ***

If interest ratesincrease, we may incur increased interest expense on variable interest ratedebt, short-term borrowings or incremental long-term debt, which could have anadverse impact on our operating results.

 

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***We are subject to capital market risk.***

*** ***

Our operations require significant capital investment in property,plant and equipment; consequently, we are an active participant in debtmarkets.  Any disruption in capitalmarkets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and areimpacted by numerous events throughout the world economy.  Capital market disruption events, such as thecollapse in the U. S. sub-prime mortgage market and subsequent broad financialmarket stress, could prevent us from issuing new securities or cause us toissue securities with less than ideal terms and conditions, such as higherinterest rates.

*** ***

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

*** ***

Credit risk includes therisk that our retail customers will not pay their bills, which may lead to areduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerousfactors including the overall economy and the price of products and servicesprovided.

 

Credit risk also includesthe risk that various counterparties that owe us money or product will breachtheir obligations.  Should thecounterparties to these arrangements fail to perform, we may be forced to enterinto alternative arrangements.  In thatevent, our financial results could be adversely affected and we could incurlosses.

 

One alternative availableto address counterparty credit risk is to transact on liquid commodityexchanges.  The credit risk is thensocialized through the exchange central clearinghouse function.  While exchanges do remove counterparty creditrisk, all participants are subject to margin requirements, which create anadditional need for liquidity to post margin as exchange positions change valuedaily.  Additional margin requirementscould impact our liquidity.

 

We may at times havedirect credit exposure in our short-term wholesale andcommodity trading activity to various financial institutions trading fortheir own accounts or issuing collateral support on behalf of othercounterparties.  We may also have someindirect credit exposure due to participation in organized markets such as thePJM Interconnection and MISO in which any credit losses are socialized to allmarket participants.

 

We do have additionalindirect credit exposures to various financial institutions in the form ofletters of credit provided as security by power suppliers undervarious long-term physical purchased power contracts.  If any ofthe credit ratings of the letter of credit issuers were to drop below thedesignated investment grade rating stipulated in the underlying long termpurchased power contracts, the supplier would need to replace that securitywith an acceptable substitute.  If the security were not replaced, theparty would be in technical default under the contract, which would enableus to exercise our contractual rights.

 

***We are subject tocommodity risks and other risks associated with energy markets and energyproduction.***

*** ***

We engage in wholesalesales and purchases of electric capacity, energy and energy-related productsand are subject to market supply and commodity price risk.  Commodity price changes can affect the valueof our commodity trading derivatives.  Wemark certain derivatives to estimated fair market value on a daily basis(mark-to-market accounting), which may cause earnings volatility.  Actual settlements can vary significantlyfrom these estimates, and significant changes from the assumptions underlyingour fair value estimates could cause significant earnings variability.

 

If we encounter market supplyshortages, we may be unable to fulfill contractual obligations to our retail,wholesale and other customers at previously authorized or anticipatedcosts.  Any such supply shortages couldcause us to seek alternative supply services at potentially higher costs orsuffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costsrelative to corresponding sales commitments would have a negative impact on ourcash flows and could potentially result in economic losses.  Potential market supply shortages may not befully resolved through alternative supply sources and such interruptions maycause short-term disruptions in our ability to provide electric and/or natural gasservices to our customers.  The impact ofthese cost and reliability issues depends on unique operating conditions suchas generation fuels mix, availability of water for cooling, availability fueltransportation, electric generation capacity, transmission, etc.

 

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***We are subject toenvironmental laws and regulations, with which compliance could be difficultand costly.***

*** ***

We are subject toenvironmental laws and regulations that affect many aspects of our past,present and future operations, including air emissions, water quality,wastewater discharges and the generation, transport and disposal of solidwastes and hazardous substances.  Theselaws and regulations require us to obtain and comply with a wide variety ofenvironmental registrations, licenses, permits, inspections and otherapprovals.  Environmental laws andregulations can also require us to restrict or limit the output of certainfacilities or the use of certain fuels, to install pollution control equipmentat our facilities, clean up spills and correct environmental hazards and othercontamination.  Both public officials andprivate individuals may seek to enforce the applicable environmental laws andregulations against us.  We may berequired to pay all or a portion of the cost to remediate (i.e. clean-up) siteswhere our past activities, or the activities of certain other parties, causedenvironmental contamination.  At Dec. 31,2009, these sites included:

 

·                  Sites of former MGPs operated by us, our predecessors,or other entities; and

·                  Third party sites, such as landfills, for which we arealleged to be a potentially responsible party that sent hazardous materials andwastes.

 

We are also subject tomandates to provide customers with clean energy, renewable energy and energyconservation offerings.  These mandatesare designed in part to mitigate the potential environmental impacts of utilityoperations.  Failure to meet therequirements of these mandates may result in fines or penalties, which couldhave a material adverse effect on our results of operations.  If our regulators do not allow us to recoverall or a part of the cost of capital investment or the operating andmaintenance costs incurred to comply with the mandates, it could have amaterial adverse effect on our results of operations.

 

In addition, existingenvironmental laws or regulations may be revised, new laws or regulationsseeking to protect the environment may be adopted or become applicable to us,including but not limited to regulation of mercury, NOx, SO2, CO2,particulates and coal ash.  We may alsoincur additional unanticipated obligations or liabilities under existingenvironmental laws and regulations.

 

***We are subject tophysical and financial risks associated with climate change.***

*** ***

**There is a growing consensus thatemissions of GHGs are linked to global climate change.  Climate change creates physical and financialrisk. **Physical risks from climate changeinclude an increase in sea level and changes in weather conditions, such as anincrease in changes in precipitation and extreme weather events.  We do not serve any coastal communities sothe possibility of sea level rises does not directly affect us or our customers.  Our customers’ energy needs vary with weatherconditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largestenergy use.  To the extent weatherconditions are affected by climate change, customers’ energy use could increaseor decrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changesmay require us to invest in more generating assets, transmission and other infrastructureto serve increased load.  Decreasedenergy use due to weather changes may affect our financial condition, throughdecreased revenues.  Extreme weatherconditions in general require more system backup, adding to costs, and cancontribute to increased system stresses, including service interruptions.  Weather conditions outside of our serviceterritory could also have an impact on our revenues.  We buy and sell electricity depending uponsystem needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/orother systems may raise electricity prices as we buy short-term energy to serveour own system, which would increase the cost of energy we provide to ourcustomers.  Severe weather impacts ourservice territories, primarily when thunderstorms, tornadoes and snow or icestorms occur.  We include stormrestoration in our budgeting process as a normal business expense and weanticipate continuing to do so.  To the extentthe frequency of extreme weather events increases, this could increase our costof providing service.  Changes inprecipitation resulting in droughts or water shortages could adversely affectour operations, principally our fossil generating units.  A negative impact to water supplies due tolong-term drought conditions could adversely impact our ability to provideelectricity to customers, as well as increase the price they pay forenergy.  We may not recover all costsrelated to mitigating these physical and financial risks.

 

To the extent climatechange impacts a region’s economic health, it may also impact ourrevenues.  Our financial performance istied to the health of the regional economies we serve.  The price of energy, as a factor in a region’scost of living as well as an important input into the cost of goods and services,has an impact on the economic health of our communities.  The cost of additional regulatoryrequirements, such as a tax on GHGs or additional environmental regulationcould impact the availability of goods and prices charged by our supplierswhich would normally be borne by consumers through higher prices for energy andpurchased goods.  To the extent financialmarkets view climate change and emissions of GHGs as a financial risk, thiscould negatively affect our ability to access capital markets or cause us toreceive less than ideal terms and conditions.

 

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***We may be subject to legislative andregulatory responses to climate change, with which compliance could bedifficult and costly.***

 

Legislative andregulatory responses related to climate change and new interpretations ofexisting laws through climate change litigation create financial risk.  Increased public awareness and concern mayresult in more regional and/or federal requirements to reduce or mitigate theeffects of GHGs.  Numerous states haveannounced or adopted programs to stabilize and reduce GHG and federal legislationhas been introduced in both houses of Congress. Our electric generating facilities are likely to be subject toregulation under climate change laws introduced at either the state or federallevel within the next few years.

 

The EPA has taken stepsto regulate GHGs under the CAA.  On Dec. 7,2009, the EPA issued a finding that GHG emissions endanger public health andwelfare and that motor vehicle emissions contribute to the GHGs in theatmosphere.  This endangerment findingcreates a mandatory duty for the EPA to regulate GHGs from light duty motorvehicles.  The EPA has proposed tofinalize GHG efficiency standards for light duty vehicles by spring 2010.  Thereafter, the EPA anticipates phasing-inpermit requirements and regulation of GHGs for large stationary sources, suchas power plants, in calendar year 2011. Xcel Energy, our parent company, is also currently a party to climatechange lawsuits and may be subject to additional climate change lawsuits,including lawsuits similar to those described in Note 15 Commitments andContingent Liabilities, in our notes to the consolidated financialstatements.  While Xcel Energy believessuch lawsuits are without merit, an adverse outcome in any of these cases couldrequire substantial capital expenditures that cannot be determined at this timeand could possibly require payment of substantial penalties or damages.  Defense costs associated with such litigationcan also be significant.  Such paymentsor expenditures could affect results of operations, cash flows, and financialcondition if such costs are not recovered through regulated rates.

 

Many of the federal andstate climate change legislative proposals, such as ACES, use a cap and tradepolicy structure, in which GHG emissions from a broad cross-section of theeconomy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage oftime.  The proposals establish mechanismsfor GHG sources, such as power plants, to obtain “allowances” or permits toemit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sellthem to other sources that do not hold enough emission allowances for their ownoperations.  Proponents of the cap andtrade policy believe it will result in the most cost effective, flexible emissionreductions.  There are manyuncertainties, however, regarding when and in what form climate changelegislation will be enacted.  **The impact oflegislation and regulations, including a cap and trade structure, on us and ourcustomers will depend on a number of factors, including whether GHG sources inmultiple sectors of the economy are regulated, the overall GHG emissions caplevel, the degree to which GHG offsets are allowed, the allocation of emissionallowances to specific sources and the indirect impact of carbon regulation onnatural gas and coal prices. **Whilewe do not have operations outside of the United States, any internationaltreaties or accords could have an impact to the extent they lead to futurefederal or state regulations.  **Another important factoris our ability to recover the costs incurred to comply with any regulatoryrequirements that are ultimately imposed. **We may not recover all costs related to complyingwith regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the costof capital investment or the operating and maintenance costs incurred to complywith the mandates, it could have a material adverse effect on our results ofoperations.

 

For further discussion,see Note 15 to the consolidated financial statements.

 

***Economic conditions couldnegatively impact our business.***

*** ***

Our operations areaffected by local, national and worldwide economic conditions.  The consequences of a prolonged recession mayinclude a lower level of economic activity and uncertainty with respect toenergy prices and the capital and commodity markets.  A lower level of economic activity mightresult in a decline in energy consumption, which may adversely affect our revenuesand future growth.  Instability in thefinancial markets, as a result of recession or otherwise, also may affect thecost of capital and our ability to raise capital, which are discussed ingreater detail in the capital market risk section above.

 

Current economicconditions may be exacerbated by insufficient financial sector liquidityleading to potential increased unemployment, and may impact customers’ abilityto pay timely, increase customer bankruptcies, and may lead to increased baddebt.  It is expected that commercial andindustrial customers will be impacted first with residential customersfollowing, if such circumstances occur. See credit risk section for more related information.

 

Further, worldwideeconomic activity has an impact on the demand for basic commodities needed forutility infrastructure, such as steel, copper, aluminum, etc., which may impactour ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.

 

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***Our utility operationsare subject to long-term planning risks.***

*** ***

On a periodic basis, oras needed, our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptionsover the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact oftechnology on sales and production, customer response and continuation of theexisting utility business model.  Giventhe uncertainty in these planning assumptions, there is a risk that themagnitude and timing of resource additions and demand may not coincide.  This could lead to under recovery of costs orinsufficient resources to meet customer demand.

 

***Our operations could beimpacted by war, acts of terrorism, threats of terrorism or disruptions innormal operating conditions due to localized or regional events.***

*** ***

Our generation plants,fuel storage facilities, transmission and distribution facilities andinformation systems may be targets of terrorist activities that could disruptour ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significantdecrease in revenues and significant additional costs to repair and insure ourassets, which could have a material adverse impact on our financial conditionand results of operations.  The potentialfor terrorism 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.  We have also already incurred increased costsfor compliance with NERC reliability standards associated with criticalinfrastructure protection, and may experience additional capital and operatingcosts to implement the NERC critical infrastructure protection standards asthey are implemented and clarified.

 

The insurance industryhas also been affected by these events and the availability of insurancecovering risks we and our competitors typically insure against maydecrease.  In addition, the insurance weare able to obtain may have higher deductibles, higher premiums and morerestrictive policy terms.

 

A disruption of theregional electric transmission grid, interstate natural gas pipeline infrastructureor other fuel sources, could negatively impact our business.  Because our generation, transmission systemsand local natural gas distribution companies are part of an interconnectedsystem, we face the risk of possible loss of business due to a disruptioncaused by the actions of a neighboring utility or an event (severe storm,severe temperature extremes, generator or transmission facility outage,pipeline rupture, railroad disruption, sudden and significant increase ordecrease in wind generation, or any disruption of work force such as may becaused by flu epidemic) within our operating systems or on a neighboringsystem.  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.

*** ***

***We are subject tobusiness continuity risks associated with our ability to respond to unforeseenevents.***

*** ***

The term businesscontinuity refers to the ability of an entity to maintain day-to-day operationsin response to unforeseen events.  Whilethe immediate response to such events may be part of a pre-existing disasterrecovery plan, business continuity is a broader concept that refers to how wellthe company responds to subsequent pressures on its day-to-day operations.  The company’s response may have beeninitially triggered by an event, but when combined with other factors, it hasan even greater and longer lasting impact on the firm’s on going businessoperations.

 

Our response tounforeseen events will, in part, determine the financial impact of the event onour financial condition and results.  It’sdifficult to predict the magnitude of such events and associated impacts.

 

***We are subject toinformation security risks.***

*** ***

A security breach of ourinformation systems could subject us to financial harm associated with theft orinappropriate release of certain types of information, including, but notlimited to, customer or system operating information.  We are unable to quantify the potentialimpact of such an event.

 

***Risingenergy prices could negatively impact our business.***

 

Higher fuel costs couldsignificantly impact our results of operations if requests for recovery areunsuccessful.  In addition, higher fuelcosts could reduce customer demand or increase bad debt expense, which couldalso have a material impact on our results of operations.  Delays in the timing of the collection offuel cost recoveries as compared with expenditures for fuel purchases couldhave an impact on our cash flows.  We areunable to predict future prices or the ultimate impact of such prices on ourresults of operations or cash flows.

 

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***Our operating results mayfluctuate on a seasonal and quarterly basis and can be adversely affected bymilder weather.***

*** ***

Our electric and naturalgas utility businesses are seasonal businesses, and weather patterns can have amaterial impact on our operating performance. Demand for electricity is often greater in the summer and winter monthsassociated with cooling and heating. Because natural gas is heavily used for residential and commercialheating, the demand for this product depends heavily upon weather patternsthroughout our service territory, and a significant amount of natural gasrevenues are recognized in the first and fourth quarters related to the heatingseason.  Accordingly, our operations havehistorically generated less revenues and income when weather conditions aremilder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on ourfinancial condition and results of operations.

 

***Our natural gasdistribution activities involve numerous risks that may result in accidents andother operating risks and costs.***

*** ***

There are inherent in ournatural gas distribution activities a variety of hazards and operating risks,such as leaks, explosions and mechanical problems, which could causesubstantial financial losses.  Inaddition, these risks could result in loss of human life, significant damage toproperty, environmental pollution, impairment of our operations and substantiallosses to us.  In accordance withcustomary industry practice, we maintain insurance against some, but not all,of these risks and losses.

 

The occurrence of any ofthese events not fully covered by insurance could have a material adverseeffect on our financial position and results of operations.  For our distribution lines located nearpopulated areas, including residential areas, commercial business centers,industrial sites and other public gathering areas, the level of damagesresulting from these risks is greater.

 

***Increased risks ofregulatory penalties could negatively impact our business.***

*** ***

The Energy Act increasedthe FERC’s civil penalty authority for violation of FERC statutes, rules andorders.  The FERC can now imposepenalties of $1 million per violation per day.  In addition, more than 120 electricreliability standards that were historically subject to voluntary complianceare now mandatory and subject to potential financial penalties by NERC or FERCfor violations.  If a serious reliabilityincident did occur, it could have a material adverse effect on our operationsor financial results.

 

***Increasing costs associated with our defined benefitretirement plans and other employee benefits may adversely******affect our results of operations, financial position, orliquidity.***

 

We have defined benefitpension and postretirement plans that cover substantially all of ouremployees.  Assumptions related to futurecosts, return on investments, interest rates and other actuarial assumptionshave a significant impact on our funding requirements related to theseplans.  These estimates and assumptionsmay change based on economic conditions, actual stock market performance,changes in interest rates and 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 and related contributions may change in the future.

 

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

*** ***

The costs of providing health care benefits to ouremployees and retirees have increased substantially in recent years.  We believe that our employee benefit costs,including costs related to health care plans for our employees and formeremployees, will continue to rise.  Theincreasing costs and funding requirements associated with our health care plansmay adversely affect our results of operations, financial position, orliquidity.

 

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

 

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

 

As of Dec. 31, 2009,Xcel Energy had approximately $7.9 billion of long-term debt and $1.0 billionof short-term debt and current maturities. Xcel Energy provides various guarantees and bond indemnities supportingsome of its subsidiaries by guaranteeing the payment or performance by thesesubsidiaries of specified agreements or transactions.

 

Xcel Energy also hasother contingent liabilities resulting from various tax disputes and othermatters.  Xcel Energy’s exposure underthe guarantees is based upon the net liability of the relevant subsidiary underthe specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximumamount that is stated in the guarantees. As of Dec. 31, 2009, Xcel Energy had guarantees outstanding with amaximum stated amount of approximately $76.4 million and $18.0 million ofexposure.  Xcel Energy has also providedindemnities to sureties in respect of bonds for the benefit of itssubsidiaries.  The total amount of bondswith these indemnities outstanding as of Dec. 31, 2009, was approximately$29.9 million.  Xcel Energy’s totalexposure under these indemnities cannot be estimated at this time.  If Xcel Energy were to become obligated tomake payments under these guarantees and bond indemnities or become obligatedto fund the other contingent liabilities, it could limit Xcel Energy’s abilityto contribute equity or make loans to us, or may cause Xcel Energy to seekadditional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need toseek alternative sources of funds to meet our cash needs.

 

***We are a wholly ownedsubsidiary of Xcel Energy.  Xcel Energycan exercise substantial control over our dividend policy and business andoperations and may exercise that control in a manner that may be perceived tobe adverse to our interests.***

*** ***

All of the members of 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.

 

We have historically paidquarterly dividends to Xcel Energy.  In2009, 2008 and 2007 we paid $266.2 million, $271.0 million and $263.9 millionof dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board of directorscould decide to increase the dividends we pay to Xcel Energy to help supportXcel Energy’s cash needs.  This couldadversely affect our liquidity.  Theamount of dividends that we can pay is limited to some extent by our indenturefor our first mortgage bonds.

 

**Item 1B —Unresolved Staff Comments**

** **

None.

 

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**Item 2 — Properties**

 

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

 

Electric utilitygenerating stations:

 
| **Station,  City and Unit**                            | ** ** | **Fuel**    | ** ** | **Installed** | ** ** | **Summer  2009 Net  Dependable  Capability (MW)** | ** ** |
|--------------------------------------------------------|------------|-------------|------------|---------------|------------|---------------------------------------------------|------------|
| ***Steam:***                                           |       |        |       |          |       |                                              |       |
| Arapahoe-Denver,  Colo., 2 Units                       |       | Coal        |       | 1951-1955     |       | 153                                               |       |
| Cameo-Grand  Junction, Colo., 2 Units                  |       | Coal        |       | 1957-1960     |       | 73                                                |       |
| Cherokee-Denver,  Colo., 4 Units                       |       | Coal        |       | 1957-1968     |       | 717                                               |       |
| Comanche-Pueblo,  Colo., 2 Units                       |       | Coal        |       | 1973-1975     |       | 660                                               | (a)        |
| Craig-Craig,  Colo., 2 Units                           |       | Coal        |       | 1979-1980     |       | 83                                                | (b)        |
| Hayden-Hayden,  Colo., 2 Units                         |       | Coal        |       | 1965-1976     |       | 238                                               | (c)        |
| Pawnee-Brush,  Colo                                    |       | Coal        |       | 1981          |       | 505                                               |       |
| Valmont-Boulder,  Colo                                 |       | Coal        |       | 1964          |       | 186                                               |       |
| Zuni-Denver,  Colo., 2 Units                           |       | Coal        |       | 1948-1954     |       | 91                                                |       |
| ***Combustion Turbine:***                              |       |        |       |          |       |                                              |       |
| Fort  St. Vrain-Platteville, Colo., 6 Units            |       | Natural Gas |       | 1972-2009     |       | 969                                               |       |
| Various  Locations, 6 Units                            |       | Natural Gas |       | Various       |       | 174                                               |       |
| ***Hydro:***                                           |       |        |       |          |       |                                              |       |
| Cabin  Creek-Georgetown, Colo., Pumped Storage 2 Units |       |        |       | 1967          |       | 210                                               |       |
| Various  Locations, 12 Units                           |       |        |       | Various       |       | 32                                                |       |
| ***Wind:***                                            |       |        |       |          |       |                                              |       |
| Ponnequin-Weld  County, Colo                           |       |        |       | 1999-2001     |       | 25                                                | (d)        |
| ***Diesel:***                                          |       |        |       |          |       |                                              |       |
| Cherokee-Denver,  Colo., 2 Units                       |       | Diesel      |       | 1967          |       | 6                                                 |       |
|                                                   |       |        |       | Total         |       | 4,122                                             |       |

 

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(a)             Construction ofComanche Unit 3, a 750 MW coal-fired unit, is expected to be completed in the firstquarter of 2010.  PSCo will own 500 MW ofthe completed unit.

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

(c)             Based on PSCo’sownership interest of 75.5 percent of Unit 1 and 37.4 percent of Unit 2.

(d)            Amountrepresents nameplate rating capacity.

 

Electric utility overheadand underground transmission and distribution lines (measured in conductormiles) at Dec. 31, 2009:

 
| **Conductor  Miles** | ** ** | ** ** | ** ** |
|----------------------|------------|------------|------------|
| 345  KV              |       | 959        |       |
| 230  KV              |       | 11,505     |       |
| 138  KV              |       | 92         |       |
| 115  KV              |       | 4,842      |       |
| Less  than 115 KV    |       | 72,980     |       |

 

PSCo had 221 electricutility transmission and distribution substations at Dec. 31, 2009.

 

Natural gas utility mainsat Dec. 31, 2009:

 
| **Miles**    |   |   |   |
|--------------|--------|--------|--------|
| Transmission |   | 2,301  |   |
| Distribution |   | 21,242 |   |

 

**Item 3 — Legal Proceedings**

** **

Inthe normal course of business, various lawsuits and claims have arisen againstPSCo.  After consultation with legalcounsel, PSCo has recorded an estimate of the probable cost of settlement orother disposition for such matters.

 

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**Additional Information**

** **

Fora discussion of legal claims and environmental proceedings, see Note 15 tothe consolidated financial statements. For a discussion of proceedings involving utility rates and otherregulatory matters, see Item 1 for Public Utility Regulation and Summaryof Recent Federal Regulatory Developments and Note 14 to the consolidatedfinancial statements.

 

**Item4 — Reserved**

 

**PART II**

** **

**Item 5 — Market forRegistrant’s Common Equity, Related Stockholder Matters and Issuer Purchases ofEquity Securities**

** **

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

 

PSCo had dividendrestrictions imposed by its credit facility and FERC rules.

 

·                 PSCo’s credit facility includes afinancial covenant that requires the equity-to-total capitalization ratio to begreater than or equal to 35 percent. PSCo was in compliance as its equity-to-total capitalization ratio was56 percent and 58 percent at Dec. 31, 2009 and 2008, respectively.

·                 Dividends are also subject to the FERC’sjurisdiction under the Federal Power Act, which prohibits the payment ofdividends out of capital accounts; payment of dividends is allowed out ofretained earnings only.

 

The dividends declaredduring 2009 and 2008 were as follows:

 
| **(Thousands  of Dollars)** | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------|------------|----------|------------|----------|------------|
| First  quarter              |       | $        | 66,816     |     | $          | 68,144 |   |
| Second  quarter             |       | 65,960   |       | 67,111   |       |
| Third  quarter              |       | 65,995   |       | 67,258   |       |
| Fourth  quarter             |       | 65,822   |       | 67,417   |       |
|                             |            |          |            |          |            |  |  |

 

**Item 6 — Selected Financial Data**

 

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

 

**Item7 — Management’s Discussion and Analysis of Financial Condition and Results ofOperations**

 

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 ownedsubsidiaries.  It is replaced withmanagement’s narrative analysis and the results of operations for the currentyear as set forth in general instructions I(2)(a) of Form 10-K forwholly owned subsidiaries (reduced disclosure format).

 

**Forward Looking 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 should be read in conjunction with therespective accompanying consolidated financial statements and notes to theconsolidated financial statements.

 

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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.  Forward-looking statementsspeak only as of the date they are made and we do not undertake any obligationto update them to reflect changes that occur after that date.  Factors that could cause actual results to differmaterially include, but are not limited to: general economic conditions,including the availability of credit and its impact on capital expenditures andthe ability of PSCo to obtain financing on favorable terms; business conditionsin the energy industry; actions of credit rating agencies; competitive factors,including the extent and timing of the entry of additional competition in themarkets served by PSCo; unusual weather; effects of geopolitical events,including war and acts of terrorism; state, federal and foreign legislative andregulatory initiatives that affect cost and investment recovery, have an impacton rates or have an impact on asset operation or ownership or imposeenvironmental compliance conditions; structures that affect the speed anddegree to which competition enters the electric and natural gas markets; costsand other effects of legal and administrative proceedings, settlements,investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies;and the other risk factors listed from time to time by PSCo in reportsfiled with the SEC, including “Risk Factors” in Item 1A of  PSCo’s Form 10-K for the year ended Dec. 31,2009 and Exhibit 99.01to PSCo’s Form 10-K for the year ended Dec. 31, 2009.

 

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

** **

**Results of Operations**

** **

PSCo’s net income wasapproximately $323.3 million for 2009, compared with approximately $339.8million for 2008.

 

**Electric Revenues and Margin**

** **

Electric fuel andpurchased power expenses tend to vary with changing retail and wholesale salesrequirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energycost-recovery mechanisms for customers, fluctuations in these costs do notmaterially affect electric margin.

 

***Electric***—******The following tables detailthe electric revenues and margin:

 
| **(Millions  of Dollars)**         | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------|------------|----------|------------|----------|------------|
| Electric  revenues                 |       | $        | 2,679      |     | $          | 2,983 |   |
| Electric  fuel and purchased power |       | (1,400   | )          | (1,819   | )          |
| Electric  margin                   |       | $        | 1,279      |     | $          | 1,164 |   |

 

Thefollowing summarizes the components of the changes in electric revenues andmargin for the year ended Dec. 31:

 

***ElectricRevenues***

** **
| **(Millions  of Dollars)**                   | ** ** | **2009  vs. 2008** | ** ** |
|----------------------------------------------|------------|--------------------|------------|
| Fuel  and purchased power cost recovery      |       | $                  | (360       | ) |
| Trading                                      |       | (51                | )          |
| Estimated  impact of weather                 |       | (16                | )          |
| Firm  wholesale                              |       | (4                 | )          |
| DSM  revenues (generally offset by expenses) |       | 71                 |       |
| Retail  rate increase                        |       | 59                 |       |
| Other,  net                                  |       | (3                 | )          |
| Total  decrease in electric revenues         |       | $                  | (304       | ) |

 

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***Electric Margin***

 
| **(Millions  of Dollars)**                   | ** ** | **2009  vs. 2008** | ** ** |
|----------------------------------------------|------------|--------------------|------------|
| DSM  revenues (generally offset by expenses) |       | $                  | 71         |   |
| Retail  rate increase                        |       | 59                 |       |
| Trading                                      |       | 9                  |       |
| Estimated  impact of weather                 |       | (16                | )          |
| Fuel  handling and procurement               |       | (3                 | )          |
| Purchased  capacity costs                    |       | (4                 | )          |
| Other,  net                                  |       | (1                 | )          |
| Total  increase in electric margin           |       | $                  | 115        |   |

 

**NaturalGas Revenues and Margin**

** **

Thecost of natural gas tends to vary with changing sales requirements and unitcost of natural gas purchases.  PSCo hasa GCA 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.

 

***Natural Gas***—******Thefollowing table details the natural gas revenues and margin:

 
| **(Millions  of Dollars)**                | ** ** | **2009** | ** ** | **2008** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Natural  gas revenues                     |       | $        | 1,094      |     | $          | 1,374 |   |
| Cost  of natural gas sold and transported |       | (712     | )          | (994     | )          |
| Natural  gas margin                       |       | $        | 382        |     | $          | 380 |   |

 

Thefollowing summarizes the components of the changes in natural gas revenues andmargin for the year ended Dec. 31:

 

***Natural Gas Revenues***

 
| **(Millions  of Dollars)**                        | ** ** | **2009  vs. 2008** | ** ** |
|---------------------------------------------------|------------|--------------------|------------|
| Purchased  natural gas adjustment clause recovery |       | $                  | (281       | ) |
| Estimated  impact of weather                      |       | (3                 | )          |
| Sales  mix                                        |       | (2                 | )          |
| Transportation                                    |       | (1                 | )          |
| DSM  revenues (generally offset by expenses)      |       | 14                 |       |
| Other,  net                                       |       | (7                 | )          |
| Total  decrease in natural gas revenues           |       | $                  | (280       | ) |

 

***Natural Gas Margin***

 
| **(Millions  of Dollars)**                   | ** ** | **2009  vs. 2008** | ** ** |
|----------------------------------------------|------------|--------------------|------------|
| Estimated  impact of weather                 |       | $                  | (3         | ) |
| Sales  mix                                   |       | (2                 | )          |
| Transportation                               |       | (1                 | )          |
| DSM  revenues (generally offset by expenses) |       | 14                 |       |
| Other,  net                                  |       | (6                 | )          |
| Total  increase in natural gas margin        |       | $                  | 2          |   |

 

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**Non-FuelOperating Expenses and Other Items**

 

***Other Operating and Maintenance Expenses****—*Other operating and maintenance expensesincreased by approximately $24.0 million, or 4.0 percent for 2009, compared to2008.  The following summarizes thecomponents of the changes in other operating and maintenance expenses for theyear ended Dec. 31:

 
| **(Millions  of Dollars)**                                  | ** ** | **2009  vs. 2008** | ** ** |
|-------------------------------------------------------------|------------|--------------------|------------|
| Higher  employee benefit costs                              |       | $                  | 32         |   |
| Higher  plant generation costs                              |       | 6                  |       |
| Lower  uncollectible receivable costs                       |       | (7                 | )          |
| Lower  consulting costs                                     |       | (3                 | )          |
| Other,  net                                                 |       | (4                 | )          |
| Total  increase in other operating and maintenance expenses |       | $                  | 24         |   |

 

***Demand SideManagement (DSM) Program Expenses****—*****DSM program expenses increased byapproximately $71.9 million for 2009, compared with 2008.  The higher expense is attributable to theexpansion of programs and regulatory commitments.

 

***Depreciation andAmortization****—*****Depreciation and amortization expenseincreased by approximately $3.7 million, or 1.5 percent, for 2009 compared with2008.  The increase is primarily due toplanned system expansion.

 

***Taxes (Other Than Income Taxes)****—*Taxes (otherthan income taxes) increased by approximately $11.0 million for 2009, comparedwith 2008.  The increase is primarily dueto an adjustment to 2009 accruals based on higher property value mill levyestimates received in 2009.

 

***Other Income, net****—*****Other income,net, decreased by approximately $12.1 million for 2009, compared with2008.  The decrease is primarily due tolower interest income, deferred compensation and a life insurance refund in2008.

 

***Interest Charges and Financing Costs****—*****Interest charges and financing costs increased byapproximately $11.9 million, or 7.7 percent, for 2009 compared with 2008.  The increase is primarily due to the issuanceof long-term debt.

 

***Allowance for FundsUsed During Construction, Equity and Debt (AFUDC)****—* AFUDC increased by approximately $5.1million, or 9.5 percent, for 2009 compared with 2008.  The increase is primarily due to the ongoingconstruction of Comanche 3, which is expected to be completed in the firstquarter of 2010.

 

***Income Taxes****—*****Income tax expense increased byapproximately $3.8 million for 2009, compared with 2008.  The effectivetax rate was 34.5 percent for 2009, compared with 32.9 percent for 2008. The increase in income tax expense and the higher effective tax rate for 2009were primarily due to additional state unitary tax expense in 2009.  If state unitary tax expense in 2008 wouldhave been consistent with 2009, the effective tax rate for 2008 would have been34.4 percent.

** **

Theeffective tax rates for 2009 and 2008 differ from their statutory federalincome tax rates, primarily due to state income tax expense partially offset bytax credits recognized and tax benefit from plant related regulatorydifferences.  See Note 8 to theconsolidated financial statements.

** **

**Item 7A — Quantitative andQualitative Disclosures About Market Risk**

** **

**Derivatives, Risk Management andMarket Risk**

 

In the normal course ofbusiness, PSCo is exposed to a variety of market risks.  Market risk is the potential loss or gainthat may occur as a result of changes in the market or fair value of aparticular instrument or commodity.  Allfinancial and commodity related instruments, including derivatives, are subjectto market risk.  Market risksassociated with derivatives are discussed in further detail in Note 11 to theconsolidated financial statements.

 

PSCo is exposed to theimpact of changes in price for energy and energy-related products, which ispartially mitigated by PSCo’s use of commodity derivatives.  Though no material non-performance riskcurrently exists with the counterparties to PSCo’s commodity derivativecontracts, distress in the financial markets may in the future impact that riskto the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securitiesin the master pension trust, as well as PSCo’s ability to earn a return onshort-term investments of excess cash.

 

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***Commodity PriceRisk —*** PSCois exposed to commodity price risk in its electric and natural gasoperations.  Commodity price risk ismanaged by entering into long- and short-term physical purchase and salescontracts for electric capacity, energy and energy-related products and forvarious fuels used in generation and distribution activities.  Commodity price risk is also managed throughthe use of financial derivative instruments. PSCo’s risk management policy allows it to manage commodity price riskwithin each rate-regulated operation to the extent such exposure exists.

 

***Short-Term Wholesale and Commodity Trading Risk —***PSCo conducts various short-termwholesale and commodity trading activities, including the purchase and sale ofelectric capacity, energy and energy-related instruments.  PSCo’s risk management policy allowsmanagement to conduct the marketing activities within guidelines andlimitations as approved by its risk management committee, which is made up ofmanagement personnel not directly involved in the activities governed by thepolicy.

 

Changesin the fair value of commodity trading contracts before the impacts ofmargin-sharing mechanisms for the years ended Dec. 31 were as follows:

 
| **(Thousands of Dollars)**                                             | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Fair  value of commodity trading net contract assets outstanding at Jan. 1  |       | $        | 554        |     | $          | 3,937 |   |
| Contracts  realized or settled during the period                                 |       | (9,867   | )          | 626      |       |
| Commodity  trading contract additions and changes during period                  |       | 9,964    |       | (4,009   | )          |
| Fair  value of commodity trading net contract assets outstanding at Dec. 31 |       | $        | 651        |     | $          | 554 |   |

 

AtDec. 31, 2009, the fair values by source for the commodity trading netasset balances were as follows:

 
| ** **                           | ** ** | **Futures  / Forwards** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | **Maturity** | ** ** | **Maturity** | ** ** | **Maturity** | ** ** | **Maturity** | ** ** | **Total  Futures/** | ** ** |
| ** **                           | ** ** | **Source  of**          | ** ** | **Less  Than** | ** ** | **1  to 3** | ** ** | **4  to 5** | ** ** | **Greater  Than** | ** ** | **Forwards** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Fair  Value**         | ** ** | **1  Year** | ** ** | **Years** | ** ** | **Years** | ** ** | **5  Years** | ** ** | **Fair  Value** | ** ** |
| PSCo                                 |       | 1                       |       | $ | (1,055 | ) | 1,158 |   | — |   | — |   | $ | 103 |   |
|                                 |       | 2                       |       | 30 |   | 222 |   | 296 |   | — |   | 548 |   |
|                                 |       |                    |       | $ | (1,025 | ) | $ | 1,380 |   | $ | 296 |   | $ | — |   | $ | 651 |   |
|                                      |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

1 — Prices activelyquoted or based on actively quoted prices.

2— Prices based on models and other valuation methods.  These represent the fair value of positionscalculated using internal models when directly and indirectly quoted externalprices or prices derived from external sources are not available.  Internal models incorporate the use ofoptions pricing and estimates of the present value of cash flows based upon underlyingcontractual terms.  The models reflectmanagement’s estimates, taking into account observable market prices, estimatedmarket prices in the absence of quoted market prices, the risk-free marketdiscount rate, volatility factors, estimated correlations of commodity pricesand contractual volumes.  Market priceuncertainty and other risks also are factored into the model.

 

Normal purchases andsales transactions, as defined by *ASC 815 Derivatives and Hedging,*hedge transactions and certain other long-termpower purchase contracts are not included in the fair values by source tablesas they are not recorded at fair value as part of commodity trading operations.

 

AtDec. 31, 2009, a 10 percent increase in market prices over the next12 months for commodity trading contracts would decrease pretax incomefrom continuing operations by approximately $0.1 million, whereas a 10percent decrease would increase pretax income from continuing operations byapproximately $0.1 million.

 

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PSCo’sshort-term wholesale and commodity trading operations measure the outstandingrisk exposure to price changes on transactions, contracts and obligations thathave been entered into, but not closed, using an industry standard methodologyknown as Value-at-Risk (VaR).  VaRexpresses the potential change in fair value on the outstanding transactions,contracts and obligations over a particular period of time under normal marketconditions.  The VaRs for the NSP-Minnesotaand PSCo commodity trading operations, calculated on a consolidated basis, wereas follows:

 
| ** **                | ** ** | **Year  Ended**  | ** ** | ** **     | ** ** | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------|------------|------------------|------------|----------------|------------|-------------|------------|------------|------------|------------|------------|
| **(Millions of Dollars)** | ** ** | **Dec. 31** | ** ** | **VaR  Limit** | ** ** | **Average** | ** ** | **High**   | ** ** | **Low**    | ** ** |
| 2009                      |       | $                | 0.50       |           | $          | 5.00        |       | $          | 0.44       |       | $          | 2.02 |   | $ | 0.06 |   |
| 2008                      |       | 0.30             |       | 5.00           |       | 0.30        |       | 1.14       |       | 0.01       |       |
|                           |            |                  |            |                |            |             |            |            |            |            |            |  |  |  |  |  |

 

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

 

AtDec. 31, 2009, a 100-basis-point change in the benchmark rate on PSCo’svariable rate debt would impact pretax interest expense by approximately $1.8million annually.  See Note 11 tothe consolidated financial statements for a discussion of PSCo’s interest ratederivatives.

 

***Credit Risk —***PSCo is also exposed to credit risk.  Credit risk relates to the risk of lossresulting from counterparties’ nonperformance of their contractualobligations.  PSCo maintains creditpolicies intended to minimize overall credit risk and actively monitors thesepolicies to reflect changes and scope of operations.

 

AtDec. 31, 2009, a 10 percent increase in prices would have resulted in anincrease in credit exposure of $23.0 million, while a decrease of 10 percent inprices would have resulted in an increase in credit exposure of $2.4 million.

 

PSCo conducts standardcredit reviews for all counterparties. PSCo employs additional credit risk control mechanisms when appropriate,such as letters of credit, parental guarantees, standardized master nettingagreements and termination provisions that allow for offsetting of positive andnegative exposures.  The credit exposureis monitored and, when necessary, the activity with a specific counterparty islimited until credit enhancement is provided. Distress in financial markets could increase PSCo’s credit risk.

 

**Fair Value Measurements**

 

PSCo adopted newaccounting and disclosure guidance on fair value measurements on Jan. 1,2008 which established a hierarchy for inputs used in measuring fair value, andgenerally requires that the most observable inputs available be used for fairvalue measurements.  Note 13 to theconsolidated financial statements describes the fair value hierarchy, anddiscloses the amounts of assets and liabilities measured at fair value thathave been assigned to Level 3.

 

***Commodity Derivatives***—PSCo continuously monitors the creditworthinessof the counterparties to its commodity derivative contracts and assesses eachcounterparty’s ability to perform on the transactions set forth in thecontracts.  Given this assessment and thetypically short duration of these contracts, the impact of discountingcommodity derivative assets for counterparty credit risk was not material tothe fair value of commodity derivative assets at Dec. 31, 2009.  Adjustments to fair value for credit risk ofcommodity trading instruments are recorded in electric revenues.  Credit risk adjustments for other commodityderivative instruments are deferred as OCI or regulatory assets andliabilities.  The classification as aregulatory asset or liability is based on commission approved regulatoryrecovery mechanisms.  PSCo also assesses the impact ofits own credit risk when determining the fair value of commodity derivativeliabilities.  The impact of discountingcommodity derivative liabilities for this credit risk was immaterial to thefair value of commodity derivative liabilities at Dec. 31, 2009.

 

Commodityderivatives assets and liabilities assigned to Level 3 consist primarily offorwards and options that are either long-term in nature or related to certaincommodities and delivery points with limited observability.  Level 3 commodity derivative assets andliabilities represent approximately 17 percent and 14 percent of total assetsand liabilities measured at fair value, respectively, at Dec. 31, 2009.

 

Determining the fair value of these commodityforwards and options can require management to make use of subjective forwardprice and volatility forecasts for commodities and locations with limitedobservability, or subjective forecasts which extend to periods beyond those readilyobservable on active exchanges or quoted by brokers.  When less observable forward price andvolatility forecasts are significant to determining the value of commodityforwards and options, these instruments are assigned to Level 3.  Level 3 commodity derivatives assets andliabilities include $2.5 million and $1.7 million of estimated fair values,respectively, for commodity forwards and options held at Dec. 31, 2009.

 

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**Item 8**— **FinancialStatements and Supplementary Data**

 

See Item 15 -1 in Part IV for an index offinancial statements included herein.

 

See Note 19 to the consolidated financialstatements for summarized quarterly financial data.

 

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**Management Report on Internal Controls OverFinancial Reporting**

 

The management of PSCo is responsible for establishingand maintaining adequate internal control over financial reporting.  PSCo’s internal control system was designedto provide reasonable assurance to the company’s management and board ofdirectors regarding the preparation and fair presentation of publishedfinancial statements.

 

All internal control systems, no matter how welldesigned, have inherent limitations. Therefore, even those systems determined to be effective can provideonly reasonable assurance with respect to financial statement preparation andpresentation.

 

PSCo management assessed the effectiveness of thecompany’s internal control over financial reporting as of Dec. 31,2009.  In making this assessment, it usedthe criteria set forth by the Committee of Sponsoring Organizations of theTreadway Commission (COSO) in *InternalControl — Integrated Framework.*Based on our assessment, webelieve that, as of Dec. 31, 2009, the company’s internal control overfinancial reporting is effective based on those criteria.

 

PSCo’sindependent auditors have issued an audit report on the company’s internalcontrol over financial reporting.  Theirreport appears herein.

 
| /S/ DAVID L. EVES                        |     | /S/ DAVID M. SPARBY                           |
|------------------------------------------|----------|-----------------------------------------------|
| David L. Eves                            |     | David M. Sparby                               |
| *President  and Chief Executive Officer* | * * | *Vice President and Chief  Financial Officer* |
| March 1, 2010                       |     | March 1, 2010                            |

 

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors and StockholderPublic Service Company of Colorado

 

We have auditedthe accompanying consolidated balance sheets and consolidated statements ofcapitalization of Public Service Company of Colorado and subsidiaries (the “Company”)as of December 31, 2009 and 2008, and the related consolidated statementsof income, common stockholder’s equity and comprehensive income, and cash flowsfor each of the three years in the period ended December 31,2009.  Our audits also included the financial statement schedulelisted in the Index at Item 15.  Thesefinancial statements and financial statement schedule are the responsibility ofthe Company’s management.  Our responsibility is to express an opinion onthe financial statements and financial statement schedule based on our audits.

 

We conducted ouraudits in accordance with the standards of the Public Company AccountingOversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

In our opinion,such consolidated financial statements present fairly, in all materialrespects, the financial position of Public Service Company of Colorado andsubsidiaries as of December 31, 2009 and 2008, and the results of theiroperations and their cash flows for each of the three years in the period endedDecember 31, 2009, in conformity with accounting principles generallyaccepted in the United States of America.  Also, in our opinion, suchfinancial statement schedule, when considered in relation to the basicconsolidated financial statements taken as a whole, presents fairly, in allmaterial respects, the information set forth therein.

 

We have alsoaudited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the Company’s internal control over financialreporting as of December 31, 2009, based on the criteria established in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commissionand our report dated March 1, 2010 expressed an unqualified opinion on theCompany’s internal control over financial reporting.

 

 
| */s/*DELOITTE &  TOUCHE LLP |   |
|--------------------------------------|--------|
| Minneapolis, Minnesota               |   |
| March 1, 2010                   |   |

 

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**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING****FIRM**

 

Board of Directors and Stockholder

Public Service Company of Colorado

 

Wehave audited the internal control over financial reporting of Public ServiceCompany of Colorado and subsidiaries (the “Company”) as of December 31,2009, based on criteria established *InternalControl — Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission.  The Company’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting, included in the accompanying Management Report on Internal Controlsover Financial Reporting.  Ourresponsibility is to express an opinion on the Company’s internal control overfinancial reporting based on our audit.

 

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects.  Our audit included obtaining an understanding ofinternal control over financial reporting, assessing the risk that a materialweakness exists, testing and evaluating the design and operating effectivenessof internal control based on the assessed risk, and performing such otherprocedures as we considered necessary in the circumstances.  We believethat our audit provides a reasonable basis for our opinion.

 

Acompany’s internal control over financial reporting is a process designed by,or under the supervision of, the company’s principal executive and principalfinancial officers, or persons performing similar functions, and effected bythe company’s board of directors, management, and other personnel to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles.  A company’s internal controlover financial reporting includes those policies and procedures that (1) pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Becauseof the inherent limitations of internal control over financial reporting,including the possibility of collusion or improper management override ofcontrols, material misstatements due to error or fraud may not be prevented ordetected on a timely basis.  Also, projections of any evaluation of theeffectiveness of the internal control over financial reporting to futureperiods are subject to the risk that the controls may become inadequate becauseof changes in conditions, or that the degree of compliance with the policies orprocedures may deteriorate.

 

In ouropinion, the Company maintained, in all material respects, effective internalcontrol over financial reporting as of December 31, 2009, based on thecriteria established in *Internal Control —Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission.

 

Wehave also audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States) the consolidated financialstatements and financial statement schedule as of and for the year ended December 31,2009 of the Company and our report dated March 1, 2010 expressed anunqualified opinion on those financial statements and financial statementschedule.

 

 

*/s/*DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

 

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**PUBLIC SERVICE CO. OF COLORADOAND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF INCOME**

*(amounts in thousands of dollars)*

 
| ** **                                                                                           | ** ** | **Year  Ended Dec. 31** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                                                           | ** ** | **2009**                     | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Operating revenues**                                                                               |       |                         |       |   |   |   |   |
| Electric                                                                                             |       | $                            | 2,678,578  |   | $ | 2,982,929 |   | $ | 2,605,388 |   |
| Natural  gas                                                                                         |       | 1,093,959                    |       | 1,373,732 |   | 1,186,106 |   |
| Steam  and other                                                                                     |       | 35,772                       |       | 36,383 |   | 36,006 |   |
| Total  operating revenues                                                                            |       | 3,808,309                    |       | 4,393,044 |   | 3,827,500 |   |
|                                                                                                 |       |                         |       |   |   |   |   |
| **Operating expenses**                                                                               |       |                         |       |   |   |   |   |
| Electric  fuel and purchased power                                                                   |       | 1,399,541                    |       | 1,818,772 |   | 1,435,680 |   |
| Cost  of natural gas sold and transported                                                            |       | 712,079                      |       | 994,221 |   | 831,826 |   |
| Cost  of sales — steam and other                                                                |       | 15,426                       |       | 15,507 |   | 15,646 |   |
| Other  operating and maintenance expenses                                                            |       | 628,999                      |       | 605,008 |   | 607,467 |   |
| Demand-side  management program expenses                                                             |       | 104,919                      |       | 32,990 |   | 18,010 |   |
| Depreciation  and amortization                                                                       |       | 256,062                      |       | 252,384 |   | 247,232 |   |
| Taxes  (other than income taxes)                                                                     |       | 95,612                       |       | 84,597 |   | 85,261 |   |
| Total  operating expenses                                                                            |       | 3,212,638                    |       | 3,803,479 |   | 3,241,122 |   |
|                                                                                                 |       |                         |       |   |   |   |   |
| **Operating income**                                                                                 |       | 595,671                      |       | 589,565 |   | 586,378 |   |
|                                                                                                 |       |                         |       |   |   |   |   |
| Other  income (expense), net                                                                         |       | 4,696                        |       | 16,748 |   | (2,400 | ) |
| Allowance  for funds used during construction — equity                                          |       | 41,118                       |       | 36,158 |   | 14,179 |   |
|                                                                                                 |       |                         |       |   |   |   |   |
| **Interest charges and financing costs**                                                             |       |                         |       |   |   |   |   |
| Interest  charges — includes other financing costs of $5,686, $5,754, and $5,599,  respectively |       | 166,212                      |       | 154,313 |   | 180,230 |   |
| Allowance  for funds used during construction — debt                                            |       | (18,452                      | )          | (18,266 | ) | (13,324 | ) |
| Total  interest charges and financing costs                                                          |       | 147,760                      |       | 136,047 |   | 166,906 |   |
|                                                                                                 |       |                         |       |   |   |   |   |
| **Income before income taxes**                                                                       |       | 493,725                      |       | 506,424 |   | 431,251 |   |
| Income  taxes                                                                                        |       | 170,405                      |       | 166,628 |   | 134,357 |   |
| **Net income**                                                                                       |       | $                            | 323,320    |   | $ | 339,796 |   | $ | 296,894 |   |

 

See Notes toConsolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF CASH FLOWS***(amounts in thousands of dollars)*

 
| ** **                                                                     | ** ** | **Year  Ended Dec. 31** | ** ** |
|--------------------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                                     | ** ** | **2009**                     | ** ** | **2008** | ** ** | **2007** | ** ** |
| **Operating activities**                                                       | ** ** | ** **                   | ** ** | ** ** |   |   |   |
| Net income                                                                     |       | $                            | 323,320    |   | $ | 339,796 |   | $ | 296,894 |   |
| Adjustments to reconcile net income to cash  provided by operating activities: |       |                         |       |   |   |   |   |
| Depreciation and amortization                                                  |       | 260,935                      |       | 260,873 |   | 254,840 |   |
| Demand-side management program expenses                                        |       | 27,625                       |       | 32,990 |   | 18,010 |   |
| Deferred income taxes                                                          |       | 197,348                      |       | 85,875 |   | 79,359 |   |
| Amortization of investment tax credits                                         |       | (2,375                       | )          | (2,760 | ) | (3,869 | ) |
| Allowance for equity funds used during construction                            |       | (41,118                      | )          | (36,158 | ) | (14,179 | ) |
| Provision for bad debts                                                        |       | 21,189                       |       | 28,372 |   | 26,149 |   |
| Net realized and unrealized hedging and derivative  transactions               |       | 42,896                       |       | (19,012 | ) | 2,583 |   |
| Changes in operating assets and liabilities:                                   |       |                         |       |   |   |   |   |
| Accounts receivable                                                            |       | 7,082                        |       | (10,469 | ) | (71,005 | ) |
| Accrued unbilled revenues                                                      |       | 40,573                       |       | 5,665 |   | (160,830 | ) |
| Recoverable purchased natural gas and electric  energy costs                   |       | (24,460                      | )          | 6,535 |   | 143,970 |   |
| Inventories                                                                    |       | (19,700                      | )          | (24,028 | ) | 29,673 |   |
| Prepayments and other                                                          |       | (44,555                      | )          | 3,438 |   | (3,198 | ) |
| Accounts payable                                                               |       | (32,982                      | )          | (607 | ) | 73,108 |   |
| Deferred electric energy costs                                                 |       | (50,205                      | )          | 78,719 |   | 30,132 |   |
| Net regulatory assets and liabilities                                          |       | 10,414                       |       | (10,310 | ) | 26,021 |   |
| Other current liabilities                                                      |       | (1,531                       | )          | 3,700 |   | 10,585 |   |
| Pension and employee benefit obligation                                        |       | (216,696                     | )          | (63,643 | ) | (43,811 | ) |
| Change in other noncurrent assets                                              |       | 375                          |       | 436 |   | (15,878 | ) |
| Change in other noncurrent liabilities                                         |       | (24,796                      | )          | 15,900 |   | (1,153 | ) |
| Net cash provided by operating activities                                      |       | 473,339                      |       | 695,312 |   | 677,401 |   |
|                                                                           |       |                         |       |   |   |   |   |
| **Investing activities**                                                       | ** ** | ** **                   | ** ** | ** ** |   |   |   |
| Utility capital/construction expenditures                                      |       | (627,421                     | )          | (809,738 | ) | (806,794 | ) |
| Allowance for equity funds used during construction                            |       | 41,118                       |       | 36,158 |   | 14,179 |   |
| Investments in utility money pool                                              |       | (274,200                     | )          | (439,500 | ) | (721,700 | ) |
| Repayments from utility money pool                                             |       | 274,200                      |       | 540,100 |   | 621,100 |   |
| Other investments                                                              |       | —                       |       | 23,716 |   | (4,451 | ) |
| Net cash used in investing activities                                          |       | (586,303                     | )          | (649,264 | ) | (897,666 | ) |
|                                                                           |       |                         |       |   |   |   |   |
| **Financing activities**                                                       | ** ** | ** **                   | ** ** | ** ** |   |   |   |
| Proceeds from (repayment of) short-term borrowings  — net                 |       | 55,000                       |       | (231,007 | ) | (101,493 | ) |
| Proceeds from issuance of long-term debt                                       |       | 394,570                      |       | 592,389 |   | 343,711 |   |
| Repayment of long-term debt, including  reacquisition premiums                 |       | (200,000                     | )          | (301,445 | ) | (101,379 | ) |
| Borrowings under utility money pool arrangement                                |       | 802,800                      |       | 755,600 |   | 486,500 |   |
| Repayments under utility money pool arrangement                                |       | (759,800                     | )          | (714,600 | ) | (486,500 | ) |
| Capital contributions from parent                                              |       | 108,813                      |       | 127,529 |   | 347,924 |   |
| Dividends paid to parent                                                       |       | (266,188                     | )          | (270,966 | ) | (263,859 | ) |
| Net cash provided by (used in) financing activities                            |       | 135,195                      |       | (42,500 | ) | 224,904 |   |
|                                                                           |       |                         |       |   |   |   |   |
| Net increase in cash and cash equivalents                                      |       | 22,231                       |       | 3,548 |   | 4,639 |   |
| Cash and cash equivalents at beginning of period                               |       | 11,198                       |       | 7,650 |   | 3,011 |   |
| Cash and cash equivalents at end of period                                     |       | $                            | 33,429     |   | $ | 11,198 |   | $ | 7,650 |   |
|                                                                           |       |                         |       |   |   |   |   |
| Supplemental disclosure of cash flow information:                              |       |                         |       |   |   |   |   |
| Cash paid for interest (net of amounts capitalized)                            |       | $                            | (147,186   | ) | $ | (131,098 | ) | $ | (130,709 | ) |
| Cash paid for income taxes, net                                                |       | (6,155                       | )          | (90,187 | ) | (61,718 | ) |
| Supplemental disclosure of non-cash investing and  financing transactions:     |       |                         |       |   |   |   |   |
| Property, plant and equipment additions in accounts  payable                   |       | $                            | 13,332     |   | $ | 16,379 |   | $ | 10,902 |   |
| Storage assets under capital lease                                             |       | 143,105                      |       | — |   | — |   |

 

See Notes toConsolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO ANDSUBSIDIARIES**

**CONSOLIDATED BALANCE SHEETS**

***(amounts in thousands of dollars)***

 
| ** **                                                                            | ** ** | **Dec. 31,** | ** ** |
|---------------------------------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                                            | ** ** | **2009**          | ** ** | **2008** | ** ** |
| **Assets**                                                                            |       |              |       |   |   |
| Current assets                                                                        |       |              |       |   |   |
| Cash and cash equivalents                                                             |       | $                 | 33,429     |   | $ | 11,198 |   |
| Accounts receivable, net                                                              |       | 330,279           |       | 362,401 |   |
| Accounts receivable from affiliates                                                   |       | 33,396            |       | 29,545 |   |
| Accrued unbilled revenues                                                             |       | 313,953           |       | 354,526 |   |
| Recoverable purchased natural gas and electric energy  costs                          |       | 25,157            |       | 697 |   |
| Inventories                                                                           |       | 253,648           |       | 233,948 |   |
| Deferred income taxes                                                                 |       | 81,980            |       | 64,181 |   |
| Derivative instruments valuation                                                      |       | 28,704            |       | 22,793 |   |
| Prepayments and other                                                                 |       | 58,968            |       | 14,413 |   |
| Total current assets                                                                  |       | 1,159,514         |       | 1,093,702 |   |
|                                                                                  |       |              |       |   |   |
| Property, plant and equipment, net                                                    |       | 8,104,841         |       | 7,592,111 |   |
|                                                                                  |       |              |       |   |   |
| Other assets                                                                          |       |              |       |   |   |
| Regulatory assets                                                                     |       | 827,311           |       | 943,012 |   |
| Derivative instruments valuation                                                      |       | 104,664           |       | 119,534 |   |
| Other                                                                                 |       | 47,175            |       | 46,610 |   |
| Total other assets                                                                    |       | 979,150           |       | 1,109,156 |   |
| Total assets                                                                          |       | $                 | 10,243,505 |   | $ | 9,794,969 |   |
|                                                                                  |       |              |       |   |   |
| **Liabilities and Equity**                                                            |       |              |       |   |   |
| Current liabilities                                                                   |       |              |       |   |   |
| Current portion of long-term debt                                                     |       | $                 | 3,964      |   | $ | 201,510 |   |
| Short-term debt                                                                       |       | 95,000            |       | 40,000 |   |
| Borrowings under utility money pool arrangement                                       |       | 84,000            |       | 41,000 |   |
| Accounts payable                                                                      |       | 422,276           |       | 470,158 |   |
| Accounts payable to affiliates                                                        |       | 40,758            |       | 28,906 |   |
| Deferred electric energy costs                                                        |       | 64,552            |       | 113,276 |   |
| Taxes accrued                                                                         |       | 80,303            |       | 72,105 |   |
| Dividends payable to parent                                                           |       | 65,822            |       | 67,417 |   |
| Derivative instruments valuation                                                      |       | 18,285            |       | 28,776 |   |
| Accrued interest                                                                      |       | 47,300            |       | 50,542 |   |
| Other                                                                                 |       | 67,692            |       | 78,192 |   |
| Total current liabilities                                                             |       | 989,952           |       | 1,191,882 |   |
|                                                                                  |       |              |       |   |   |
| Deferred credits and other liabilities                                                |       |              |       |   |   |
| Deferred income taxes                                                                 |       | 1,447,143         |       | 1,204,861 |   |
| Deferred investment tax credits                                                       |       | 50,031            |       | 52,406 |   |
| Regulatory liabilities                                                                |       | 510,491           |       | 514,445 |   |
| Pension and employee benefit obligations                                              |       | 257,881           |       | 527,264 |   |
| Customer advances                                                                     |       | 271,171           |       | 290,937 |   |
| Derivative instruments valuation                                                      |       | 49,587            |       | 62,126 |   |
| Asset retirement obligations                                                          |       | 65,160            |       | 61,505 |   |
| Other                                                                                 |       | 31,287            |       | 22,491 |   |
| Total deferred credits and other liabilities                                          |       | 2,682,751         |       | 2,736,035 |   |
|                                                                                  |       |              |       |   |   |
| Commitments and contingent liabilities                                                |       |              |       |   |   |
| Capitalization                                                                        |       |              |       |   |   |
| Long-term debt                                                                        |       | 2,824,988         |       | 2,289,251 |   |
| Common stock — authorized 100 shares of $0.01 par  value; outstanding 100 shares |       | —            |       | — |   |
| Additional paid-in capital                                                            |       | 2,995,470         |       | 2,886,657 |   |
| Retained earnings                                                                     |       | 742,243           |       | 683,516 |   |
| Accumulated other comprehensive income                                                |       | 8,101             |       | 7,628 |   |
| Total common stockholder’s equity                                                |       | 3,745,814         |       | 3,577,801 |   |
| Total liabilities and equity                                                          |       | $                 | 10,243,505 |   | $ | 9,794,969 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLICSERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITYAND COMPREHENSIVE INCOME**

*(amounts inthousands of dollars, except share data)*

 
| ** **                                                                                             | ** ** | **Common Stock Issued** | ** ** | ** **     | ** ** | **Accumulated**  | ** ** | **Total**    | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|----------------|------------|------------------|------------|--------------|------------|
| ** **                                                                                             | ** ** | ** **                        | ** ** | ** **     | ** ** | **Additional**   | ** ** | ** **   | ** ** | **Other** | ** ** | **Common** | ** ** |
| ** **                                                                                             | ** ** | ** **                        | ** ** | ** **     | ** ** | **Paid In** | ** ** | **Retained** | ** ** | **Comprehensive** | ** ** | **Stockholders’** | ** ** |
| ** **                                                                                             | ** ** | **Shares**                        | ** ** | **Par  Value** | ** ** | **Capital**      | ** ** | **Earnings** | ** ** | **Income (Loss)** | ** ** | **Equity** | ** ** |
| **Balance at Dec. 31, 2006**                                                                      |       | 100                               |       | $              | —     |             | $          | 2,411,204    |       | $ | 585,219 |   | $ | 12,614 |   | $ | 3,009,037 |   |
| Adoption of new accounting guidance for uncertainty  in income taxes                                   |       |                              |       |           |       |             |       | (312         | )          |   |   | (312 | ) |
| Net income                                                                                             |       |                              |       |           |       |             |       | 296,894      |       |   |   | 296,894 |   |
| Net derivative instrument fair value changes during  the period, net of tax of $(92)                   |       |                              |       |           |       |             |       |         |       | (167 | ) | (167 | ) |
| Comprehensive income for 2007                                                                          |       |                              |       |           |       |             |       |         |       |   |   | 296,727 |   |
| Common dividends declared to parent                                                                    |       |                              |       |           |       |             |       | (267,534     | )          |   |   | (267,534 | ) |
| Contribution of capital by parent                                                                      |       |                              |       |           |       | 347,924          |       |         |       |   |   | 347,924 |   |
| **Balance at Dec. 31, 2007**                                                                      |       | 100                               |       | $              | —     |             | $          | 2,759,128    |       | $ | 614,267 |   | $ | 12,447 |   | $ | 3,385,842 |   |
| Adoption of new accounting guidance for endorsement  split-dollar life insurance, net of tax of $(391) |       |                              |       |           |       |             |       | (617         | )          |   |   | (617 | ) |
| Net income                                                                                             |       |                              |       |           |       |             |       | 339,796      |       |   |   | 339,796 |   |
| Net derivative instrument fair value changes during  the period, net of tax of $(2,910)                |       |                              |       |           |       |             |       |         |       | (4,819 | ) | (4,819 | ) |
| Comprehensive income for 2008                                                                          |       |                              |       |           |       |             |       |         |       |   |   | 334,977 |   |
| Common dividends declared to parent                                                                    |       |                              |       |           |       |             |       | (269,930     | )          |   |   | (269,930 | ) |
| Contribution of capital by parent                                                                      |       |                              |       |           |       | 127,529          |       |         |       |   |   | 127,529 |   |
| **Balance at Dec. 31, 2008**                                                                      |       | 100                               |       | $              | —     |             | $          | 2,886,657    |       | $ | 683,516 |   | $ | 7,628 |   | $ | 3,577,801 |   |
| Net income                                                                                             |       |                              |       |           |       |             |       | 323,320      |       |   |   | 323,320 |   |
| Net derivative instrument fair value changes during  the period, net of tax of $298                    |       |                              |       |           |       |             |       |         |       | 473 |   | 473 |   |
| Comprehensive income for 2009                                                                          |       |                              |       |           |       |             |       |         |       |   |   | 323,793 |   |
| Common dividends declared to parent                                                                    |       |                              |       |           |       |             |       | (264,593     | )          |   |   | (264,593 | ) |
| Contribution of capital by parent                                                                      |       |                              |       |           |       | 108,813          |       |         |       |   |   | 108,813 |   |
| **Balance at Dec. 31, 2009**                                                                      |       | 100                               |       | $              | —     |             | $          | 2,995,470    |       | $ | 742,243 |   | $ | 8,101 |   | $ | 3,745,814 |   |

 

See Notes to Consolidated Financial Statements

 

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**PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES**

**CONSOLIDATED STATEMENTS OFCAPITALIZATION**

***(amounts in thousands of dollars)***

 
| ** **                                                                                              | ** ** | **Dec. 31** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                              | ** ** | **2009**         | ** ** | **2008** | ** ** |
| **Long-Term Debt**                                                                                      |       |             |       |   |   |
| First  Mortgage Bonds, Series due:                                                                 |       |             |       |   |   |
| 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 |   |
| Aug. 1,  2018, 5.8%                                                                                |       | 300,000          |       | 300,000 |   |
| Jan. 1,  2019, 5.1% (a)                                                                            |       | 48,750           |       | 48,750 |   |
| June 1,  2019, 5.125%                                                                              |       | 400,000          |       | — |   |
| Sept.  1, 2037, 6.25%                                                                                   |       | 350,000          |       | 350,000 |   |
| Aug. 1,  2038, 6.5%                                                                                |       | 300,000          |       | 300,000 |   |
| Unsecured  Senior A Notes, due July 15, 2009, 6.875%                                               |       | —           |       | 200,000 |   |
| Capital  lease obligations, through 2060, 11.2% — 14.1%                                            |       | 183,026          |       | 43,423 |   |
| Unamortized  debt                                                                                       |       | (7,324           | )          | (5,912 | ) |
| Total                                                                                                   |       | 2,828,952        |       | 2,490,761 |   |
| Less  current maturities                                                                                |       | 3,964            |       | 201,510 |   |
| Total  long-term debt                                                                                   |       | $                | 2,824,988  |   | $ | 2,289,251 |   |
|                                                                                                    |       |             |       |   |   |
| **Common Stockholder’s Equity**                                                                    |       |             |       |   |   |
| Common  stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in  2009 and 2008 |       | $                | —     |   | $ | — |   |
| Additional  paid-in capital                                                                             |       | 2,995,470        |       | 2,886,657 |   |
| Retained  earnings                                                                                      |       | 742,243          |       | 683,516 |   |
| Accumulated  comprehensive income                                                                       |       | 8,101            |       | 7,628 |   |
| Total  common stockholder’s equity                                                                 |       | $                | 3,745,814  |   | $ | 3,577,801 |   |

 

----

(a) Pollution control financing

 

See Notes to Consolidated Financial Statements

 

37

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**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1.  Summary of Significant Accounting Policies**

** **

***Businessand System of Accounts*****— PSCois principally engaged in the generation, purchase, transmission, distributionand sale of electricity and in the purchase, transportation, distribution andsale of natural gas.  PSCo is subject toregulation by the FERC and the CPUC.  Allof PSCo’s accounting records conform to the FERC uniform system of accounts orto systems required by various state regulatory commissions, which are the samein all material respects.

 

***Principlesof Consolidation*****— PSCohas subsidiaries, which have been consolidated and for which all intercompanytransactions and balances have been eliminated.

 

***RevenueRecognition*****—Revenues related to the sale of energy are generally recorded when service isrendered or energy is delivered to customers. However, the determination of the energy sales to individual customersis based on the reading of their meter, which occurs on a systematic basisthroughout the month.  At the end of eachmonth, amounts of energy delivered to customers since the date of the lastmeter reading are estimated and the corresponding unbilled revenue isestimated.  PSCo presents its revenue netof any excise or other fiduciary-type taxes or fees.

 

PSCo has variousrate-adjustment mechanisms in place that currently provide for the recovery ofnatural gas and electric fuel costs, as well as purchased energy costs.  These cost-adjustment tariffs may increase ordecrease the level of costs recovered through base rates and are revisedperiodically for any difference between the total amount collected under theclauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rateorders, fuel costs over-recoveries (the excess of fuel revenue billed tocustomers over fuel costs incurred) are deferred as current regulatoryliabilities and under-recoveries (the excess of fuel costs incurred over fuelrevenues billed to customers) are deferred as current regulatory assets.  A summary of significant rate-adjustmentmechanisms follows:

 

·                 PSCo generally recovers all prudently incurred electricfuel and purchased energy costs through the ECA for the company’s retailjurisdiction.  The ECA mechanism was extended in 2009 and wentinto effect in January 2010.  The ECA allows for sharing of margins on shortterm energy sales.

·                 PSCo generally recovers all purchased capacity coststhrough the PCCA for the company’s retail jurisdiction.  The PCCA mechanism is revised annually.  The PCCA was recently extended by CPUC orderin PSCo’s most recent rate case.

·                 PSCo’s rates include annual adjustmentsfor the recovery of conservation and energy-management program costs, as wellas a financial incentive based on its performance in achieving establishedgoals.  PSCo is allowed to recovercertain costs associated with renewable energy resources through a specificretail rate rider.  In January 2008,a new recovery mechanism for transmission commenced.  The TCA permits PSCo to recover costsassociated with investment in transmission facilities made after March 2007through a rate rider.

·                 PSCo sellsfirm power and energy in wholesale markets, which are regulated by theFERC.  Certain of these rates includemonthly wholesale fuel cost-recovery mechanisms.

 

***CommodityTrading Operations*****— Allapplicable gains and losses related to commodity trading activities, whether ornot settled physically, are shown on a net basis in the consolidated statementsof income.

 

Pursuant to the JOAapproved by the FERC, some of the commodity trading margins from PSCo areapportioned to NSP-Minnesota and SPS.  Commoditytrading activities are not associated with energy produced from PSCo’sgeneration assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded atfair market value in accordance with *ASC 815 Derivatives and Hedging*. In addition, commodity trading results include the impact of allmargin-sharing mechanisms.  For moreinformation, see Note 11 to the consolidated financial statements.

 

***FairValue Measurements******—*** PSCo presents cashequivalents, interest rate derivatives, and commodity derivatives at estimatedfair values in its consolidated financial statements.  Cash equivalents are recorded at cost plusaccrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents,including commercial paper and money market funds, are also monitored asadditional support for determining fair value and losses are recorded inearnings if fair value falls below recorded cost.  For interest ratederivatives, quoted prices based primarily on observable market interest ratecurves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputsavailable are generally used to determine the fair value of each contract.  In the absence of a quoted price for anidentical contract in an active market, PSCo may use quoted prices for similarcontracts, or internally prepared valuation models as primary inputs todetermine fair value.

 

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***Typesof and Accounting for Derivative Instruments****—*PSCo uses derivative instruments in connection withits interest rate, utility commodity price, vehicle fuel price, short-termwholesale and commodity trading activities, including forward contracts,futures, swaps and options.  Allderivative instruments not designated and qualifying for the normal purchasesand normal sales exception, as defined by *ASC 815 Derivatives and Hedging*, are recorded on the consolidatedbalance sheets at fair value as derivative instruments valuation.  This includes certain instruments used tomitigate market risk for the utility operations and all instruments related tothe commodity trading operations.  Theclassification of changes in fair value for those derivative instruments isdependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivativeinstruments not designated in a qualifying hedging relationship are reflectedin current earnings or as a regulatory asset or liability.  The classification is dependent on theapplicability of specific regulation.

 

Gains or losses onhedging transactions for the sale of energy or energy-related products areprimarily recorded as a component of revenue; hedging transactions for fuelused in energy generation are recorded as a component of fuel costs; hedgingtransactions for natural gas purchased for resale are recorded as a componentof natural gas costs; hedge transactions for vehicle fuel costs are recorded asa component of capital projects or O&M costs; and interest rate 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 purchased toreduce commodity cost volatility.

 

*Cash Flow Hedges* — Qualifying hedging relationships aredesignated as a hedge of a forecasted transaction or future cash flow (cashflow hedge).  The accounting for derivatives requires that the hedging relationshipbe highly effective and that a company formally designate a hedgingrelationship to apply hedge accounting. PSCo formally documents all hedging relationships in accordance withthis guidance.  The documentationincludes, among other factors, the identification of the hedging instrument andthe hedged transaction, as well as the risk management objectives andstrategies for undertaking the hedging transaction.  In addition, at inception and on a quarterlybasis, PSCo formally assesses whether the derivative instruments being used arehighly effective in offsetting changes in the cash flows of the hedged items.

 

Changes in the fair valueof a derivative designated and qualified as a cash flow hedge, to the extent effectiveare included in OCI, or deferred as a regulatory asset or liability based onrecovery mechanisms until earnings are affected by the hedged transaction.  PSCo discontinues hedge accountingprospectively when it has determined that a derivative no longer qualifies asan effective hedge, or when it is no longer probable that the hedged forecastedtransaction will occur.  To test theeffectiveness of hedges, a hypothetical hedge is used to mirror all the criticalterms of the hedged transaction and the dollar-offset method is utilized toassess the effectiveness of the actual hedge at inception and on an ongoingbasis.  Gains and losses related todiscontinued hedges that were previously deferred in OCI or deferred asregulatory assets or liabilities will remain deferred until the hedgedtransaction is reflected in earnings, unless it is probable that the hedgedforecasted transaction will not occur, in which case associated deferredamounts are immediately recognized in current earnings.

 

*Normal Purchases and Normal Sales* — PSCo enters into contracts for thepurchase and sale of commodities for use in their business operations.  *ASC 815 Derivatives and Hedging* requires a company to evaluate thesecontracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition ofa derivative may be exempted as normal purchases or normal sales.

 

PSCo evaluates all of itscontracts at inception to determine if they are derivatives and if they meetthe normal purchases and normal sales designation requirements.  None of the contracts entered into within thecommodity trading operations qualify for a normal purchases and normal salesdesignation.

 

For further discussion ofPSCo’s risk management and derivative activities see Note 11 to theconsolidated financial statements.

 

***Property,Plant and Equipment and Depreciation*****— Property, plant and equipment is stated at originalcost.  The cost of plant includes directlabor and materials, contracted work, overhead costs and applicable interestexpense.  The cost of plant retired ischarged to accumulated depreciation and amortization.  Regulatory obligations to incur removal costsare recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized,while repair and maintenance costs are charged to expense as incurred.  Maintenance and replacement of itemsdetermined to be less than units of property are charged to operating expensesas incurred.  Planned major maintenanceactivities are charged to operating expense unless the cost represents theacquisition of an additional unit of property or the replacement of an existingunit of property.  Property, plant andequipment also includes costs associated with property held for future use.

 

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PSCo records depreciationexpense related to its plant by using the straight-line method over the plant’suseful life.  Actuarial andsemi-actuarial life studies are performed on a periodic basis and submitted tothe state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and netsalvage rates are used to calculate depreciation.  Depreciation expense, expressed as apercentage of average depreciable property, for the years ended Dec. 31,2009, 2008 and 2007 was 2.6 percent, 2.7 percent and 2.7 percent, respectively.

 

***AFUDC*****— AFUDC represents the cost of capital used to financeutility construction activity.  AFUDC iscomputed by applying a composite pretax rate to qualified construction work inprogress.  The amount of AFUDCcapitalized as a utility construction cost is credited to other nonoperatingincome (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included inPSCo’s rate base for establishing utility service rates.

 

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

 

Estimated remediationcosts, excluding inflationary increases, are recorded.  The estimates are based on experience, anassessment of the current situation and the technology currently available foruse in the remediation.  The recordedcosts are regularly adjusted as estimates are revised and remediation proceeds.  If several designated responsible partiesexist, costs are estimated and recorded only for PSCo’s expected share of thecost.  Any future costs of restoringsites where operation may extend indefinitely are treated as a capitalized costof plant retirement.  The depreciationexpense levels recoverable in rates include a provision for removal expenses,which may include final remediation costs. Removal costs recovered in rates are classified as a regulatoryliability.

 

***LegalCosts*** —Litigation accruals are recorded when it is probable PSCo is liable for thecosts and the liability can be reasonably estimated.  External legal fees related to settlementsare expensed as incurred.

 

***IncomeTaxes*****— PSCo accounts for income taxes usingthe asset and liability method, which requires the recognition of deferred taxassets and liabilities for the expected future tax consequences of events thathave been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financialand taxable income, and between the book and tax bases of assets andliabilities.  PSCo uses the tax ratesthat are scheduled to be in effect when the temporary differences are expectedto reverse.  The effect of a change intax rates on deferred tax assets and liabilities is recognized in income in theperiod that includes the enactment date.

 

Deferred tax assets arereduced by a valuation allowance if, based on the weight of available evidence,it is more likely than not that some portion or all of the deferred tax assetwill not be realized.  In making such adetermination, all available positive and negative evidence, includingscheduled reversals of deferred tax liabilities, projected future taxable income,tax planning strategies and recent financial operations, is considered.

 

Investment tax creditsare deferred and their benefits amortized over the book depreciable lives ofthe related property.  Utility rateregulation also has created certain regulatory assets and liabilities relatedto income taxes, which are summarized in Note 16 to the consolidated financialstatements.  For more information onincome taxes, see Note 8 to the consolidated financial statements.

 

PSCofollows the guidance in *ASC 740 Income Taxes*to measure and disclose uncertain tax positions that PSCo has taken or expectsto take in its income tax returns.  Inaccordance with this guidance, PSCo recognizes a tax position in itsconsolidated financial statements when it is more likely than not that theposition will be sustained upon examination based on the technical merits ofthe position.  Recognition of changes inuncertain tax positions are reflected as a component of income tax expense.

 

PSCo reportsinterest and penalties related to income taxes within the other income andinterest charges sections in the consolidated statements of income.

 

Xcel Energy and itssubsidiaries, including PSCo, file consolidated federal income tax returns andcombined and separate state income tax returns. Federal income taxes paid by Xcel Energy, as parent of the Xcel Energyconsolidated group, are allocated to the Xcel Energy subsidiaries based onseparate company computations of tax.  Asimilar allocation is made for state income taxes paid by Xcel Energy inconnection with combined state filings. The holding company also allocates its own net income tax benefits toits direct subsidiaries based on the positive tax liability of each company.

 

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***Useof Estimates*****— Inrecording transactions and balances resulting from business operations, PSCouses estimates based on the best information available.  Estimates are used for such items as plantdepreciable lives, AROs, decommissioning, tax provisions, uncollectibleamounts, environmental costs, unbilled revenues, jurisdictional fuel and energycost allocations and actuarially determined benefit costs.  The recorded estimates are revised whenbetter information becomes available or when actual amounts can bedetermined.  Those revisions can affectoperating results.  The depreciable livesof certain plant assets are reviewed annually, and revised, if appropriate.

 

***Cashand Cash Equivalents*****— PSCoconsiders investments in certain instruments, including commercial paper andmoney market funds, with a remaining maturity of three months or less at thetime of purchase, to be cash equivalents.

 

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

 

***RegulatoryAccounting*****— PSCoaccounts for certain income and expense items in accordance with *ASC 980Regulated Operations.* Under this guidance:

 

·                 Certain costs, which would otherwise be charged toexpense, are deferred as regulatory assets based on the expected ability torecover them in future rates; and

·                 Certain credits, which would otherwise be reflected asincome, are deferred as regulatory liabilities based on the expectation theywill be returned to customers in future rates.

 

Estimates of recoveringdeferred costs and returning deferred credits are based on specific ratemakingdecisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with theperiod 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 16 to the consolidated financial statements.

 

***DeferredFinancing Costs*****— Otherassets included deferred financing costs, net of amortization, of approximately$17.5 million and $16.4 million at Dec. 31, 2009 and 2008,respectively.  PSCo is amortizing thesefinancing costs over the remaining maturity periods of the related debt.

 

Debtpremiums, discounts and expenses are amortized over the life of the relateddebt.  The premiums, discounts andexpenses associated with refinanced debt are deferred and amortized over thelife of the related new issuance, in accordance with regulatory guidelines.

 

***AccountsReceivable and Allowance for Bad Debts*****—**Accounts receivable are stated at the actual billedamount net of write-offs and an allowance for bad debts.  PSCo establishes an allowance foruncollectible receivables based on a reserve policy that reflects its expectedexposure to the credit risk of customers.

 

***RenewableEnergy Credits  —***RECs are******marketableenvironmental commodities that represent proof that energy was generated fromeligible renewableenergy sources.  RECs are awarded upondelivery of the associated energyand can be bought and sold. RECs are typically used as a form of measurement of compliance to RPSsenacted by those states that are encouraging construction and consumption ofrenewable energy, but can also be sold separately from the energyproduced.  Currently, PSCo acquires RECsfrom the generation or purchase of renewable power.

 

***When RECs are acquired in the course of generation or purchase as aresult of meeting load obligations, they are recorded as inventory atcost.  RECs acquired for trading purposesare recorded as other investments and are also recorded at cost.  The cost of RECs that are retired forcompliance purposes is recorded as electric fuel and purchased powerexpense.  The net margin on sales of RECsfor trading purposes is recorded as electric utility operating revenues, net ofany margin sharing requirements.***

*** ***

***EmissionAllowances*****—**Emissionallowances are recorded at cost, including the annual SO2 and NOxemission allowance entitlement received at no cost from the EPA.  PSCo follows the inventory accounting modelfor all allowances.  The sales ofallowances are reported in the operating activities section of the consolidatedstatements of cash flows.  The net marginon sales of emission allowances is included in electric utility operatingrevenues as it is integral to the production process of energy and our revenueoptimization strategy for our utility operations.

 

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***Reclassifications****** —*** Demand side management program expenseswere reclassified as a separate item from depreciation and amortization withinthe consolidated statements of cash flows. Pension and employee benefit obligations were reclassified as a separateitem from change in other noncurrent liabilities within the consolidatedstatements of cash flows.  Thereclassifications did not have an impact on net cash provided by operatingactivities.

 

***Subsequent Events*** —Management hasevaluated the impact of events occurring after Dec. 31, 2009 up to thedate of issuance of these consolidated financial statements.  These statements contain all necessaryadjustments and disclosures resulting from that evaluation.

 

**2.**             AccountingPronouncements

** **

***Recently Adopted***

 

***Business Combinations*******—****In December 2007,the FASB issued new guidance on business combinations which establishesprinciples and requirements for how an acquirer in a business combinationrecognizes and measures in its financial statements the identifiable assetsacquired, the liabilities assumed, and any noncontrolling interest; recognizesand measures the goodwill acquired in the business combination or a gain from abargain purchase; and determines what information to disclose to enable usersof the financial statements to evaluate the nature and financial effects of thebusiness combination. This new guidance is to be applied prospectively tobusiness combinations for which the acquisition date is on or after thebeginning of an entity’s fiscal year that begins on or after Dec. 15,2008.  PSCo implemented the guidance on Jan. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

***Noncontrolling Interests***— Also in December 2007,the FASB issued new guidance on noncontrolling interests in consolidatedfinancial statements which establishes accounting and reporting standards thatrequire the ownership interest in subsidiaries held by parties other than theparent be clearly identified and presented in the consolidated balance sheetswithin equity, but separate from the parent’s equity; the amount ofconsolidated net income attributable to the parent and the noncontrollinginterest be clearly identified and presented on the face of the consolidatedstatement of earnings; and changes in a parent’s ownership interest while theparent retains its controlling financial interest in its subsidiary be accountedfor consistently as equity transactions. This new guidance was effective forfiscal years beginning on or after Dec. 15, 2008.  PSCo implemented the guidance on Jan. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

***Derivatives and Hedging Disclosures***— In March 2008,the FASB issued new guidance on disclosures about derivative instruments andhedging activities which is intended to enhance disclosures to help users ofthe financial statements better understand how derivative instruments andhedging activities affect an entity’s financial position, financial performanceand cash flows.  The guidance amends andexpands previous disclosurerequirements for derivative instruments and hedging activities, includingdisclosures of objectives and strategies for using derivatives, gains andlosses on derivative instruments, and credit-risk-related contingent featuresin derivative contracts.  This newguidance was effective for fiscal years and interim periods beginning after Nov. 15,2008.  PSCo implemented the guidance on Jan. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.  For furtherdiscussion and the required disclosures, see Note 11 to the consolidatedfinancial statements.

 

***Interim Fair Value Disclosures***—******In April 2009,the FASB issued new guidance on interim disclosures about fair value offinancial instruments which requires that disclosures regarding the fair valueof financial instruments be included in interim financial statements.****** This new guidance was effective for interimperiods ending after June 15, 2009. PSCo implemented the guidance on April 1, 2009, and theimplementation did not have a material impact on its consolidated financialstatements.

 

***Fair Value in Inactive Markets***—******Also in April 2009,the FASB issued new guidance for identifying market transactions that are notorderly and determining fair value when market trading activity has decreasedsignificantly.  The new guidanceemphasizes that even if there has been a significant decrease in the volume andlevel of market activity for an asset or liability, fair value still representsthe exit price in an orderly transaction between market participants.  This new guidance was effective for interimand annual periods ending after June 15, 2009.  PSCo implemented the guidance on April 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

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***Other-Than-Temporary Impairments***—******Additionally in April 2009,the FASB issued new guidance on recognition and presentation ofother-than-temporary impairments which changes the method for determiningwhether an other-than-temporary impairment exists for debt securities, and alsorequires additional disclosures regarding other-than-temporaryimpairments.  This new guidance waseffective for interim and annual periods ending after June 15, 2009.  PSCo implemented the guidance on April 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

 

***Accounting Standards Codification***— In June 2009,the FASB issued *Topic 105 — GenerallyAccepted Accounting Principles Amendments Based on Statement of FinancialAccounting Standards No. 168 — The FASB Accounting Standards Codificationand the Hierarchy of Generally Accepted Accounting Principles (AccountingStandards Update (ASU) No. 2009-01)*, which updates the FASB ASCto state that the Codification is to be the single source of authoritativeGAAP, other than the guidance put forth by the SEC.  All other accounting literature not includedin the Codification is to be considered non-authoritative.  The updates to the Codification contained inASU No. 2009-01 were effective for interim and annual periods ending afterSept. 15, 2009.  PSCo implemented theguidance set forth by ASU No. 2009-01, recognizing the Codification as thesingle source of authoritative GAAP, other than the guidance put forth by theSEC, on July 1, 2009.  Theimplementation did not have a material impact on PSCo’s consolidated financialstatements.

 

***Postretirement Benefit Plans***— In December 2008, the FASB issuednew guidance on employers’ disclosures about postretirement benefit planassets.  The guidance amends and expands previous disclosurerequirements for plan assets of a defined benefit pension or otherpostretirement plan to include investment policies and strategies, majorcategories of plan assets, and information regarding fair valuemeasurements.  This new guidance waseffective for disclosures for fiscal years ending after Dec. 15,2009.  PSCo implemented the guidance on Jan. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.  For furtherdiscussion and the required disclosures, see Note 9 to the consolidatedfinancial statements.

*** ***

***Fair Value of Liabilities*****—****In August 2009, the FASB issued *Fair Value Measurements and Disclosures (Topic 820) —Measuring Liabilities at Fair Value (ASU No. 2009-05)*, whichupdates the Codification with clarifications for measuring the fair value ofliabilities.  The liability-specificguidance includes clarifications and guidelines for using, when available, themost observable prices in active markets for identical liabilities or similarliabilities, or the prices of identical liabilities or similar liabilitiestraded as assets, rather than more complex and less observable valuationtechniques and inputs such as those used in a present value model.  The updates to the Codification contained inASU No. 2009-05 were effective for interim and annual periods beginningafter its August, 2009 issuance.  PSCo implemented the guidance on Sept. 1,2009, and the implementation did not have a material impact on its consolidatedfinancial statements.

*** ***

***Recently Issued***

 

***Consolidation of Variable Interest Entities***— In June 2009, the FASB issued new guidance on consolidation ofvariable interest entities.****** The guidance willsignificantly affect various elements of consolidation under existingaccounting standards, including the determination of whether an entity is avariable interest entity and whether an enterprise is a variable interestentity’s primary beneficiary.  This newguidance is effective for interim and annual periods beginning after Nov. 15,2009.  PSCo does not expect theimplementation of the guidance to have a material impact on its consolidatedfinancial statements.

 

***Fair Value Measurement Disclosures*** — In January 2010, theFASB issued *Fair Value Measurements and Disclosures (Topic 820)— Improving Disclosures about Fair Value Measurements (ASU No. 2010-06)*,which will update the Codification to require new disclosures for assets andliabilities measured at fair value.  Therequirements include expanded disclosure of valuation methodologies for Level 2and Level 3 fair value measurements, transfers in and out of Levels 1 and 2,and gross rather than net presentation of certain changes in Level 3 fair valuemeasurements.  The updates to theCodification contained in ASU No. 2010-06 are effective for interim andannual periods beginning after Dec. 15, 2009, except for requirementsrelated to gross presentation of certain changes in Level 3 fair valuemeasurements, which are effective for interim and annual periods beginningafter Dec. 15, 2010.  PSCo does notexpect the implementation of the guidance to have a material impact on itsconsolidated financial statements.

 

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**3.****             ****Selected Balance Sheet Data**

 
| **(Thousands of Dollars)**   | ** ** | **Dec. 31, 2009** | ** ** | **Dec. 31, 2008** | ** ** |
|----------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| **Accounts receivable, net**           |       |                        |       |                        |       |
| Accounts  receivable                   |       | $                           | 354,428    |                        | $          | 391,596 |   |
| Less  allowance for bad debts          |       | (24,149                     | )          | (29,195                     | )          |
|                                   |       | $                           | 330,279    |                        | $          | 362,401 |   |
| **Inventories**                        |       |                        |       |                        |       |
| Materials  and supplies                |       | $                           | 45,809     |                        | $          | 40,451 |   |
| Fuel                                   |       | 96,964                      |       | 41,456                      |       |
| Natural  gas                           |       | 110,875                     |       | 152,041                     |       |
|                                   |       | $                           | 253,648    |                        | $          | 233,948 |   |
| **Property, plant and equipment, net** |       |                        |       |                        |       |
| Electric  plant                        |       | $                           | 7,635,325  |                        | $          | 7,089,763 |   |
| Natural  gas plant                     |       | 2,133,116                   |       | 1,914,565                   |       |
| Common  and other property             |       | 731,511                     |       | 739,453                     |       |
| Construction  work in progress         |       | 1,038,013                   |       | 1,086,627                   |       |
| Total  property, plant and equipment   |       | 11,537,965                  |       | 10,830,408                  |       |
| Less  accumulated depreciation         |       | (3,433,124                  | )          | (3,238,297                  | )          |
|                                   |       | $                           | 8,104,841  |                        | $          | 7,592,111 |   |

 

**4.   Short-TermBorrowings**

 

***Commercial Paper*****— At Dec. 31, 2009 and 2008, PSCo had commercialpaper outstanding of approximately $95.0 million and $40.0 million,respectively.  PSCo has approval by theBoard of Directors to issue up to $700 million of commercial paper.  The weighted average interest rates at Dec. 31,2009 and 2008 were 0.35 percent and 1.55 percent, respectively.

 

***Money Pool*****— Xcel Energy and its utility subsidiaries haveestablished a utility money pool arrangement that allows for short-terminvestments in and borrowings from the utility subsidiaries between eachother.  The Holding Company may makeinvestments in the utility subsidiaries at market-based interest rates.  However, the money pool arrangement does notallow the utility subsidiaries to make investments in the Holding Company.  PSCo has approval to borrow up to $250million under the arrangement.  At Dec. 31,2009 and 2008, PSCo had money pool borrowings of $84.0 million and $41.0million, respectively.  The weightedaverage interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and3.48 percent, respectively.

 

**5.   Long-TermDebt**

 

***Credit Facilities***— At Dec. 31, 2009, PSCo had thefollowing committed credit facility in effect, in millions of dollars:

 
| **Credit**   | ** ** | ** ** | ** ** | ** **    | ** ** | ** **         | ** ** | ** **   | ** ** |
|--------------|------------|------------|------------|---------------|------------|--------------------|------------|--------------|------------|
| **Facility** | ** ** | **Drawn*** | ** ** | **Available** | ** ** | **Original  Term** | ** ** | **Maturity** | ** ** |
| $            |  675  |       | $          | 99            |       | $                  | 576        |         | Five year  |   | December 2011 |   |
|              |            |            |            |               |            |                    |            |              |            |  |  |  |

 

----

* Includes direct borrowings, outstandingcommercial paper and issued and outstanding letters of credit.

 

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 financial covenantrequiring that PSCo’s debt-to-total capitalization ratio be less than or equalto 65 percent.  PSCo was in compliance asits debt-to-total capitalization ratio was 45 percent and 42 percent at Dec. 31,2009 and 2008, respectively.  If PSCodoes not comply with the covenant, it is deemed an event of default and anyoutstanding amounts due under the facility can be declared due by the lender.

 

·                 The credit facility has a cross default provision thatprovides the borrower will be in default on its borrowings under the facilityif any of its subsidiaries, comprising more than 15 percent of the consolidatedassets, defaults on any of its indebtedness greater than $50 million.

 

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·                 The interest rate is based on either the agent bank’sprime rate or the applicable LIBOR, plus a borrowing margin as based on PSCo’ssenior unsecured credit ratings from Moody’s, Standard & Poor’s andFitch.  Based on PSCo’s current creditratings the borrowing margin is 35 points. The commitment fees are calculated for the unused portion of the creditfacility at 8 basis points for PSCo.

 

·                 At Dec. 31, 2009, PSCo had no direct borrowingson this line of credit; however, the credit facility was used to provideback-up support for $95.0 million of commercial paper outstanding and $4.6million of letters of credit.  At Dec. 31,2008, PSCo had no direct borrowings on this line of credit; however, the creditfacility was used to provide back-up support for $40.0 million of commercialpaper outstanding and $4.9 million of letters of credit.

 

***Long-Term Borrowings***

 

InJune 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds,series due 2019.  PSCo added the proceedsfrom the sale of the first mortgage bonds to its general funds and applied aportion of the net proceeds to fund the payment at maturity of $200 million of6.875 percent unsecured senior notes due July 15, 2009.

 

In August 2008, PSCoissued $300 million of 5.80 percent first mortgage bonds, series due Aug. 1,2018 and $300 million of 6.50 percent first mortgage bonds, series due Aug. 1,2038.  PSCo added the net proceeds fromthe sale of the first mortgage bonds to its general funds and applied a portionof such net proceeds to fund the payment at maturity of $300 million of 4.375percent first mortgage bonds due Oct. 1, 2008.

 

Maturities of long-termdebt are:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2010                                |       | $          | 4          |   |
| 2011                                |       | 7          |       |
| 2012                                |       | 606        |       |
| 2013                                |       | 257        |       |
| 2014                                |       | 282        |       |
|                                     |            |            |            |  |

 

**6.   PreferredStock**

 

PSCo has authorized theissuance of preferred stock.

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

 

**7.   JointPlant Ownership**

 

Following are theinvestments by PSCo in jointly owned plants and the related ownershippercentages as of Dec. 31, 2009:

 
| ** **                                                | ** ** | ** **    | ** ** | ** **       | ** ** | **Construction** | ** ** | ** **       | ** ** |
|-----------------------------------------------------------|------------|---------------|------------|------------------|------------|------------------|------------|------------------|------------|
| ** **                                                | ** ** | **Plant  in** | ** ** | **Accumulated**  | ** ** | **Work  in**     | ** ** | ** **       | ** ** |
| **(Thousands of Dollars)**                      | ** ** | **Service**   | ** ** | **Depreciation** | ** ** | **Progress**     | ** ** | **Ownership  %** | ** ** |
| Hayden  Unit 1                                            |       | $             | 88,840     |             | $          | 56,695           |       | $                | 393        |   | 75.5 |   |
| Hayden  Unit 2                                            |       | 81,606        |       | 53,179           |       | 7,624            |       | 37.4             |       |
| Hayden  common facilities                                 |       | 32,695        |       | 12,369           |       | 118              |       | 53.1             |       |
| Craig  Units 1 and 2                                      |       | 53,254        |       | 31,471           |       | 860              |       | 9.7              |       |
| Craig  common facilities 1, 2 and 3                       |       | 33,258        |       | 14,723           |       | 565              |       | 6.5 - 9.7        |       |
| Comanche  Unit 3                                          |       | 3,721         |       | 4                |       | 761,418          |       | 66.7             |       |
| Transmission  and other facilities, including substations |       | 143,936       |       | 53,218           |       | 3,213            |       | 11.6 - 68.1      |       |
| Total                                                     |       | $             | 437,310    |             | $          | 221,659          |       | $                | 774,191    |   |   |   |

 

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PSCo’scurrent operational assets include approximately 320 MWs of jointly ownedgenerating capacity, excluding Comanche Unit 3. PSCo’s share of operating expenses and construction expenditures areincluded in the applicable utility accounts. Each of the respective owners is responsible for the issuance of its ownsecurities to finance its portion of the construction costs.  PSCo began major construction on a new jointlyowned 750 MW, coal-fired unit in Pueblo, Colo. in January 2006.  Major construction on the new unit, ComancheUnit 3, was still underway in 2009 and in-service is expected by theend of the first quarter of 2010.  Theplant experienced certain boiler tube leaks in the start-up process that arebeing resolved.  PSCo is the operatingagent under the joint ownership agreement.

 

**8.  Income Taxes**

 

***COLI*** — In 2007, Xcel Energy and the U.S. governmentsettled an ongoing dispute regarding PSCo’s right to deduct interest expense onpolicy loans related to its COLI program that insured lives of certain PSCoemployees.  These COLI policies wereowned and managed by PSRI, a wholly owned subsidiary of PSCo.  The total exposure for the tax years indispute through 2007 was approximately $583 million, which includes income tax,interest and potential penalties.  As aresult of the settlement, the lawsuit filed by Xcel Energy in the United StatesDistrict Court has been dismissed and the Tax Court proceedings are in theprocess of being dismissed.  Weanticipate these proceedings to be dismissed in 2010.

 

**Terms of the Final Settlement**

 

1.              Xcel Energy paid the government a total of $64.4million in full settlement of the government’s claims for tax, penalty, andinterest for tax years 1993-2007.

 

2.              The recognition of this settlement resulted in totalexpense of $59.5 million, including federal and state tax, interest on thefederal and state tax liabilities, penalties, and tax benefits on the interestexpense for the nine months ended Sept. 30, 2007.  The expense of $59.5 million includes $43.4million of interest and penalties and income tax of $16.1 million (net of taxbenefit on the interest expense of $14.3 million).

 

3.              Xcel Energy surrendered the policies to its insurer onOct. 31, 2007, without recognizing a taxable gain.

 

***Federal Audit******—***PSCo is a member of theXcel Energy affiliated group that files a consolidated federal income taxreturn. *** ***In 2008, the IRS completed an examination of XcelEnergy’s federal income tax returns for 2004 and 2005 (and research credits for2003).******TheIRS did not propose any material adjustments for those tax years.  Thestatute of limitations applicable to Xcel Energy’s 2004 and 2005 federal incometax returns expired on Dec. 31, 2009.  The IRS commenced anexamination of tax years 2006 and 2007 in 2008, and this audit is expected tobe completed in the first quarter of 2010.  As of Dec. 31, 2009, theIRS had not proposed any material adjustments to tax years 2006 and 2007.

 

***StateAudits*** — PSCo is a member of the Xcel Energy affiliated group that filesconsolidated state income tax returns.  Asof Dec. 31, 2009, PSCo’s earliest open tax year that is subject toexamination by state taxing authorities under applicable statutes of limitationsis 2004.  There currently are no state income tax audits in progress.

 

***UnrecognizedTax Benefits*** — Theamount of unrecognized tax benefits was $7.2 million and $10.3 million on Dec. 31,2009 and Dec. 31, 2008, respectively.  A reconciliation of the beginningand ending amount of unrecognized tax benefit is as follows:

 
| **(Millions of Dollars)**                            | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------------|------------|----------|------------|----------|------------|
| Balance  at Jan. 1                                        |       | $        | 10.3       |     | $          | 8.8 |   |
| Additions  based on tax positions related to the current year  |       | 3.7      |       | 2.9      |       |
| Reductions  based on tax positions related to the current year |       | (0.3     | )          | (0.5     | )          |
| Additions  for tax positions of prior years                    |       | 2.2      |       | 2.0      |       |
| Reductions  for tax positions of prior years                   |       | (0.5     | )          | (0.2     | )          |
| Settlements  with taxing authorities                           |       | (8.2     | )          | —   |       |
| Lapse  of applicable statutes of limitations                   |       | —   |       | (2.7     | )          |
| Balance  at Dec. 31                                       |       | $        | 7.2        |     | $          | 10.3 |   |

 

The unrecognized tax benefit amountswere reduced by the tax benefits associated with net operating loss (NOL) andtax credit carryovers of $4.0 million and $5.8 million on Dec. 31, 2009and Dec. 31, 2008, respectively.

 

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The unrecognized tax benefit balanceincluded $1.0 million and $1.4 million of tax positions on Dec. 31, 2009and Dec. 31, 2008, respectively, which if recognized would affect theannual effective tax rate.  In addition, the unrecognized tax benefitbalance included $6.2 million and $8.9 million of tax positions on Dec. 31,2009 and Dec. 31, 2008, respectively, for which the ultimate deductibilityis highly certain but for which there is uncertainty about the timing of suchdeductibility.  A change in the period of deductibility would not affectthe effective tax rate but would accelerate the payment of cash to the taxingauthority to an earlier period.

 

The decrease in theunrecognized tax benefit balance of $3.1 million in 2009 was due to theresolution of certain federal audit matters, partially offset by an increasedue to the addition of similar uncertain tax positions related to ongoingactivity.  PSCo’s amount of unrecognized tax benefits could significantlychange in the next 12 months when the IRS and state audits resume.  Atthis time, due to the uncertain nature of the audit process, it is notreasonably possible to estimate an overall range of possible change.

 

Areconciliation of the beginning and ending amount of the payable for interestrelated to unrecognized tax benefits is as follows:

 
| **(Millions of Dollars)**                                        | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Payable  for interest related to unrecognized tax benefits at Jan. 1  |       | $        | (0.4       | )        | $          | (3.8 | ) |
| Interest  income related to unrecognized tax benefits                      |       | 0.3      |       | 3.4      |       |
| Payable  for interest related to unrecognized tax benefits at Dec. 31 |       | $        | (0.1       | )        | $          | (0.4 | ) |

 

Noamounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31,2009 or Dec. 31, 2008.

 

***Other Income Tax Matters —***NOL and tax credit carryforwards as of Dec. 31, 2009 and 2008 wereas follows:

 
| **(Millions of Dollars)**                       | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------------------------|------------|----------|------------|----------|------------|
| Federal  NOL carryforward                                 |       | $        | 158.8      |     | $          | 40.1 |   |
| Federal  tax credit carryforwards                         |       | 13.6     |       | 12.1     |       |
| State  NOL carryforward                                   |       | 97.5     |       | 63.6     |       |
| State  tax credit carryforwards, net of federal detriment |       | 7.1      |       | 5.8      |       |
|                                                           |            |          |            |          |            |  |  |

 

The federal carryforwardperiods expire between 2021 and 2029. The state carryforward periods expire between 2016 and 2029.

 

Total income tax expense from operations differs fromthe amount computed by applying the statutory federal income tax rate to incomebefore income tax expense.  The followingreconciles such differences for the years ending Dec. 31:

 
| ** **                                                 | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal  statutory rate                                    |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  (decreases) in tax from:                        |       |     |       |     |       |     |       |
| State  income taxes, net of federal income tax benefit     |       | 3.3      |       | 1.7      |       | 1.2      |       |
| Regulatory  differences — utility plant items         |       | (2.7     | )          | (2.2     | )          | (0.8     | )          |
| Life  insurance policies                                   |       | —   |       | (0.2     | )          | (7.2     | )          |
| Tax  credits recognized, net of federal income tax expense |       | (1.0     | )          | (1.1     | )          | (1.6     | )          |
| Resolution  of income tax audits and other                 |       | 0.1      |       | 0.3      |       | (1.8     | )          |
| Change  in unrecognized tax benefits                       |       | (0.1     | )          | (0.3     | )          | 6.6      |       |
| Other,  net                                                |       | (0.1     | )          | (0.3     | )          | (0.2     | )          |
| Effective  income tax rate                                 |       | 34.5     | %          | 32.9     | %          | 31.2     | %          |

 

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The components of income tax expense for the yearsending Dec. 31 were:

 
| **(Thousands of Dollars)**                   | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current  federal tax expense (benefit)                 |       | $        | (20,867    | )        | $          | 77,865   |       | $ | 29,496 |   |
| Current  state tax expense (benefit)                   |       | (2,327   | )          | 6,219    |       | (2,077   | )          |
| Current  change in unrecognized tax expense (benefit)  |       | (1,374   | )          | (571     | )          | 31,448   |       |
| Deferred  federal tax expense                          |       | 172,454  |       | 81,326   |       | 78,508   |       |
| Deferred  state tax expense                            |       | 27,508   |       | 8,859    |       | 7,414    |       |
| Deferred  change in unrecognized tax expense (benefit) |       | 864      |       | (841     | )          | (2,782   | )          |
| Deferred  tax credits                                  |       | (3,478   | )          | (3,469   | )          | (3,781   | )          |
| Deferred  investment tax credits                       |       | (2,375   | )          | (2,760   | )          | (3,869   | )          |
| Total  income tax expense                              |       | $        | 170,405    |     | $          | 166,628  |       | $ | 134,357 |   |

 

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

 
| **(Thousands of Dollars)**                                                                   | ** ** | **2009** | ** ** | **2008** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred  tax expense excluding items below                                                            |       | $        | 224,484    |     | $          | 109,504 |   |
| Amortization  and adjustments to deferred income taxes onincome tax regulatory assets and  liabilities |       | (26,838  | )          | (26,540  | )          |
| Tax  expense allocated to other comprehensive income and other                                         |       | (298     | )          | 2,911    |       |
| Deferred  tax expense                                                                                  |       | $        | 197,348    |     | $          | 85,875 |   |

 

The components of net deferred tax liability (currentand noncurrent) at Dec. 31 were as follows:

 
| **(Thousands of Dollars)**               | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------------------------------|------------|----------|------------|----------|------------|
| Deferred  tax liabilities:                         |       |     |       |     |       |
| Difference  between book and tax bases of property |       | $        | 1,352,421  |     | $          | 1,176,313 |   |
| Employee  benefits                                 |       | 98,835   |       | 33,819   |       |
| Regulatory  assets                                 |       | 62,876   |       | 52,728   |       |
| Deferred  fuel costs                               |       | 49,557   |       | 35,442   |       |
| Other                                              |       | 11,243   |       | 17,024   |       |
| Total  deferred tax liabilities                    |       | $        | 1,574,932  |     | $          | 1,315,326 |   |
|                                               |       |     |       |     |       |
| Deferred  tax assets:                              |       |     |       |     |       |
| Unbilled  revenue - fuel costs                     |       | $        | 59,318     |     | $          | 78,175 |   |
| NOL  carryforward                                  |       | 67,749   |       | 24,420   |       |
| Tax  credit carryforward                           |       | 20,737   |       | 17,931   |       |
| Deferred  investment tax credits                   |       | 19,011   |       | 19,891   |       |
| Regulatory  liabilities                            |       | 20,371   |       | 16,166   |       |
| Bad  debts                                         |       | 9,176    |       | 11,082   |       |
| Deferred  rent                                     |       | 4,142    |       | —   |       |
| Other                                              |       | 9,264    |       | 6,981    |       |
| Total  deferred tax assets                         |       | $        | 209,768    |     | $          | 174,646 |   |
| Net  deferred tax liability                        |       | $        | 1,365,164  |     | $          | 1,140,680 |   |

 

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**9.  Benefit Plans and Other PostretirementBenefits**

** **

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

 

Xcel Energy, whichincludes PSCo, offers various benefit plans to its employees.  At Dec. 31, 2009, PSCo had 2,124bargaining employees covered under a collective-bargaining agreement, which expiresin May 2014.

 

EffectiveJan. 1, 2009, Xcel Energy and PSCo adopted new guidance onemployers’ disclosures about pension and postretirement benefit planassets.  The new guidance expandsemployers’ disclosure requirements for benefit plan assets, includinginvestment policies and strategies, major categories of plan assets, andinformation regarding fair value measurements consistent with the disclosuresfor entities’ recurring fair value measurements prescribed by *ASC 820 Fair Value Measurements*.

 

*ASC 820Fair Value Measurements* establishes a hierarchal framework fordisclosing the observability of the inputs utilized in measuring fairvalue.  The three levels defined by thehierarchy and examples of each level are as follows:

 

Level1 — Quoted prices are available in active markets for identical assets as ofthe reporting date.  The types of assetsincluded in Level 1 are highly liquid and actively traded instruments withquoted prices, such as common stocks listed by the New York Stock Exchange.

 

Level2 — Pricing inputs are other than quoted prices in active markets, but areeither directly or indirectly observable as of the reporting date.  The types of assets included in Level 2 aretypically either comparable to actively traded securities or contracts orpriced with models using highly observable inputs, such as corporate bonds withpricing based on market interest rate curves and recent trades of similarlyrated securities.

 

Level3 — Significant inputs to pricing have little or no observability as of thereporting date.  The types of assetsincluded in Level 3 are those with inputs requiring significant managementjudgment or estimation, such as asset and mortgage backed securities, for whichsubjective risk-based adjustments to estimated yield and forecasted prepaymentsare significant inputs.

 

**Pension Benefits**

** **

Xcel Energy, whichincludes PSCo, has several noncontributory, defined benefit pension plans thatcover almost all employees.  Benefits arebased on a combination of years of service, the employee’s average pay andSocial Security benefits.  Xcel Energy’sand PSCo’s policy is to fully fund the actuarially determined pension costsrecognized for ratemaking and financial reporting purposes, subject to thelimitations of applicable employee benefit and tax laws, into an external trustover time.

 

XcelEnergy and PSCo base the investment-return assumption on expected long-termperformance for each of the investment types included in the pension assetportfolio and consider the actual historical returns achieved by its assetportfolio over the past 20-year or longer period, as well as the long-termreturn levels projected and recommended by investment experts.  The historical weighted average annual returnfor the past 20 years for the portfolio of pension investmentsis 8.98 percent, which is greater than the current assumptionlevel.  The pension cost determination assumes a forecasted mix ofinvestment types over the long term.  Investment returns in 2009were above the assumed level of 8.50 percent while returns in2008 and 2007 were below the assumed level of8.75 percent.  Xcel Energy and PSCo continually review thepension assumptions.  In 2010, Xcel Energy will use an investment-returnassumption, for all pension plans in aggregate, of 7.79 percent.

 

Theassets are invested in a portfolio according to Xcel Energy’s and PSCo’sreturn, liquidity and diversification objectives to provide a source of fundingfor plan obligations and minimize the necessity of contributions to the plan,within appropriate levels of risk.  Theprincipal mechanism for achieving these objectives is the allocation of assetsto selected asset classes, given the long term risk, return, and liquiditycharacteristics of each particular asset class. There were no significant concentrations of risk in any particularindustry, index, or entity, however, a higher weighting in equity investmentscan increase the volatility in the return levels achieved by pension assets inany year.

 

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Thefollowing table presents the target pension asset allocations for 2009 and2008:

 
| ** **                                          | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------------------|------------|----------|------------|----------|------------|
| Domestic  and international equity securities       |       | 24       | %          | 52       | %          |
| Long  duration fixed income securities              |       | 34       |       | —   |       |
| Short  to intermediate term fixed income securities |       | 19       |       | 25       |       |
| Alternative  investments                            |       | 18       |       | 23       |       |
| Cash                                                |       | 5        |       | —   |       |
| Total                                               |       | 100      | %          | 100      | %          |

 

In2009, Xcel Energy and PSCo engaged J.P. Morgan’s Pension Advisory Group toevaluate the allocation of the total assets in the master pension trust, takinginto consideration the funded status of each individual pension.  The investment strategy employed during 2009is based on plan-specific investment recommendations that seek to minimizepotential investment and interest rate risk as a plan’s funded status increasesover time.  The investmentrecommendations result in a greater percentage of short-to-intermediate termand long-duration fixed income securities being allocated to specific planshaving relatively higher funded status ratios, and a greater percentage ofgrowth assets being allocated to plans having relatively lower funded statusratios.  The aggregate asset allocationpresented in the table above for the master pension trust results from theplan-specific strategies.

 

**PensionPlan Assets**

 

Thefollowing table presents, for each of the fair value hierarchy levels, pensionplan assets that are measured at fair value as of Dec. 31, 2009:

 
| **(Thousands of Dollars)**                       | ** ** | **Level  1** | ** ** | **Level  2** | ** ** | **Level  3** | ** ** | **Total** | ** ** |
|------------------------------------------------------------|------------|--------------|------------|--------------|------------|--------------|------------|-----------|------------|
| Cash  equivalents                                          |       | $            | —     |         | $          | 221,971      |       | $         | —     |   | $ | 221,971 |   |
| Short-term  investments & money market securities |       | —       |       | 324,683      |       | —       |       | 324,683   |       |
| Derivatives                                                |       | —       |       | 11,606       |       | —       |       | 11,606    |       |
| Government  securities                                     |       | —       |       | 94,949       |       | —       |       | 94,949    |       |
| Corporate  bonds                                           |       | —       |       | 522,403      |       | —       |       | 522,403   |       |
| Asset-backed &  mortgage-backed securities        |       | —       |       | —       |       | 191,831      |       | 191,831   |       |
| Common  stock                                              |       | 89,260       |       | —       |       | —       |       | 89,260    |       |
| Private  equity investments                                |       | —       |       | —       |       | 82,098       |       | 82,098    |       |
| Commingled  equity and bond funds                          |       | —       |       | 1,014,072    |       | —       |       | 1,014,072 |       |
| Real  estate                                               |       | —       |       | —       |       | 66,704       |       | 66,704    |       |
| Securities  lending collateral obligation and other        |       | —       |       | (170,251     | )          | —       |       | (170,251  | )          |
| Total                                                      |       | $            | 89,260     |         | $          | 2,019,433    |       | $         | 340,633    |   | $ | 2,449,326 |   |

 

Thefollowing table presents the changes in Level 3 pension plan assets for theyear ended Dec. 31, 2009:

 
| **(Thousands of Dollars)**                | ** ** | **Jan. 1,  2009** | ** ** | **Realized  and  Unrealized  Gains  (Losses)** | ** ** | **Purchases,  Issuances,  and  Settlements  (net)** | ** ** | **Dec. 31,  2009** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|------------------------------------------------|------------|-----------------------------------------------------|------------|-------------------------|------------|
| Asset-backed &  mortgage-backed securities |       | $                      | 244,008    |                                           | $          | 151,755                                             |       | $                       | (203,932   | ) | $ | 191,831 |   |
| Real  estate                                        |       | 109,289                |       | (43,207                                        | )          | 622                                                 |       | 66,704                  |       |
| Private  equity investments                         |       | 81,034                 |       | (5,682                                         | )          | 6,746                                               |       | 82,098                  |       |
| Total                                               |       | $                      | 434,331    |                                           | $          | 102,866                                             |       | $                       | (196,564   | ) | $ | 340,633 |   |

 

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***Benefit Obligations***— A comparison of the actuarially computed pensionbenefit obligation and plan assets, on a combined basis, is presented in thefollowing table:

 
| **(Thousands of Dollars)**                                                                                           | ** ** | **2009**            | ** ** | **2008**            | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|
| **Accumulated Benefit Obligation at Dec. 31**                                                                             |       | $                   | 2,676,174  |                | $          | 2,435,513 |   |
|                                                                                                                           |       |                |       |                |       |
| **Change in Projected Benefit Obligation:**                                                                                    |       |                |       |                |       |
| Obligation  at Jan. 1                                                                                                     |       | $                   | 2,598,032  |                | $          | 2,662,759 |   |
| Service  cost                                                                                                                  |       | 65,461              |       | 62,698              |       |
| Interest  cost                                                                                                                 |       | 169,790             |       | 167,881             |       |
| Plan  amendments                                                                                                               |       | (35,341             | )          | —              |       |
| Actuarial  loss (gain)                                                                                                         |       | 223,122             |       | (47,509             | )          |
| Benefit  payments                                                                                                              |       | (191,433            | )          | (247,797            | )          |
| Obligation  at Dec. 31                                                                                                    |       | $                   | 2,829,631  |                | $          | 2,598,032 |   |
|                                                                                                                           |       |                |       |                |       |
| **Change in Fair Value of Plan Assets:**                                                                                       |       |                |       |                |       |
| Fair  value of plan assets at Jan. 1                                                                                      |       | $                   | 2,185,203  |                | $          | 3,186,273 |   |
| Actual  return (loss) on plan assets                                                                                           |       | 255,556             |       | (788,273            | )          |
| Employer  contributions                                                                                                        |       | 200,000             |       | 35,000              |       |
| Benefit  payments                                                                                                              |       | (191,433            | )          | (247,797            | )          |
| Fair  value of plan assets at Dec. 31                                                                                     |       | $                   | 2,449,326  |                | $          | 2,185,203 |   |
|                                                                                                                           | ** ** | ** **          |       |                |       |
| **Funded Status of Plans at Dec. 31:**                                                                                    |       |                |       |                |       |
| Funded  status                                                                                                                 |       | $                   | (380,305   | )                   | $          | (412,829 | ) |
| Noncurrent  assets                                                                                                             |       | —              |       | 15,612              |       |
| Noncurrent  liabilities                                                                                                        |       | (380,305            | )          | (428,441            | )          |
| Net  pension amounts recognized on consolidated balance sheets                                                                 |       | $                   | (380,305   | )                   | $          | (412,829 | ) |
|                                                                                                                           |       |                |       |                |       |
| **PSCo Amounts Not Yet Recognized as Components of Net Periodic  Benefit Cost:**                                               |       |                |       |                |       |
| Net  loss                                                                                                                      |       | $                   | 447,815    |                | $          | 394,045 |   |
| Prior  service (credit) cost                                                                                                   |       | (22,221             | )          | 17,287              |       |
| Total                                                                                                                          |       | $                   | 425,594    |                | $          | 411,332 |   |
|                                                                                                                           |       |                |       |                |       |
| **Amounts Related to the Funded Status of the Plans Have Been  Recorded as****Follows Based Upon Expected Recovery in Rates:** |       |                |       |                |       |
| Regulatory  assets                                                                                                             |       | $                   | 425,594    |                | $          | 411,332 |   |
| Total                                                                                                                          |       | $                   | 425,594    |                | $          | 411,332 |   |
|                                                                                                                           |       |                |       |                |       |
| PSCo  accrued benefit liability recorded                                                                                       |       | 90,989              |       | 251,178             |       |
|                                                                                                                           |       |                |       |                |       |
| **Measurement Date**                                                                                                           |       | Dec. 31,  2009 |       | Dec. 31,  2008 |       |
|                                                                                                                           |       |                |       |                |       |
| **Significant Assumptions Used to Measure Benefit  Obligations:**                                                              |       |                |       |                |       |
| Discount  rate for year-end valuation                                                                                          |       | 6.00                | %          | 6.75                | %          |
| Expected  average long-term increase in compensation level                                                                     |       | 4.00                |       | 4.00                |       |
| Mortality  table                                                                                                               |       | RP                  | 2000       |                | RP         | 2000 |   |
|                                                                                                                                |            |                     |            |                     |            |  |  |  |  |

 

AtDec. 31, 2009, Xcel Energy’s pension plans, in the aggregate, had planassets of $2.4 billion and projected benefit obligations of $2.8 billion.  At Dec. 31, 2008, one of the pensionplans had plan assets of $259.9 million, which exceeded projected benefitobligations of $244.3 million and all other plans in the aggregate hadplan assets of $1.9 billion and projected benefit obligations of$2.4 billion.

 

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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.  Theseregulations did not require cash funding for 2007 through 2009 for the pensionplans and are not expected to require cash funding in 2010.

 

XcelEnergy accelerated its planned 2010 contribution of $100 million based onavailable liquidity, bringing its total pension contributions to $200 millionduring 2009.

 

·                 Voluntarycontributions were made to the PSCo Bargaining Pension Plan of $173 million in2009, $35 million in 2008 and $35 million in 2007.

·                 Voluntarycontributions were made to the NCE Non-Bargaining Pension Plan of$27 million in 2009.  No voluntary contributionswere made to the plan during 2007 or 2008.

·                 Pension fundingcontributions for 2011, which will be dependent on several factors including,realized asset performance, future discount rate, IRS and legislativeinitiatives as well as other actuarial assumptions, are estimated to rangebetween $100 million to $150 million.

 

***Plan Amendments —***The decrease inthe projected benefit obligation for the plan amendment is due to a change inthe average earnings calculation resulting from negotiations with the PSCoBargaining Pension Plan.

 

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

 
| **(Thousands of Dollars)**                       | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service  cost                                              |       | $        | 65,461     |     | $          | 62,698   |       | $ | 61,392 |   |
| Interest  cost                                             |       | 169,790  |       | 167,881  |       | 162,774  |       |
| Expected  return on plan assets                            |       | (256,538 | )          | (274,338 | )          | (264,831 | )          |
| Amortization  of prior service cost                        |       | 24,618   |       | 20,584   |       | 25,056   |       |
| Amortization  of net loss                                  |       | 12,455   |       | 11,156   |       | 15,845   |       |
| Net  periodic pension cost(credit)                         |       | 15,786   |       | (12,019  | )          | 236      |       |
|                                                       |       |     |       |     |       |     |       |
| **PSCo:**                                                  |       |     |       |     |       |     |       |
| Net  periodic pension cost                                 |       | 13,847   |       | 11,120   |       | 18,348   |       |
|                                                       |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs:**         |       |     |       |     |       |     |       |
| Discount  rate for year-end valuation                      |       | 6.75     | %          | 6.25     | %          | 6.00     | %          |
| Expected  average long-term increase in compensation level |       | 4.00     |       | 4.00     |       | 4.00     |       |
| Expected  average long-term rate of return on assets       |       | 8.50     |       | 8.75     |       | 8.75     |       |
|                                                            |            |          |            |          |            |          |            |  |  |  |

 

Pensioncosts include an expected return impact for the current year that may differfrom actual investment performance in the plan. The return assumption used for 2010 pension cost calculations will be7.79 percent.  The cost calculationuses a market-related valuation of pension assets.  Xcel Energy, including PSCo, uses acalculated value method to determine the market-related value of the planassets.  The market-related value beginswith the fair market value of assets as of the beginning of the year.  The market-related value is determined byadjusting the fair market value of assets to reflect the investment gains andlosses (the difference between the actual investment return and the expectedinvestment return on the market-related value) during each of the previous fiveyears at the rate of 20 percent per year.

 

XcelEnergy, which includes PSCo, also maintains noncontributory, defined benefitsupplemental retirement income plans for certain qualifying executivepersonnel.  Benefits for these unfundedplans are paid out of operating cash flows.

 

**Defined Contribution Plans**

** **

Xcel Energy, whichincludes PSCo, maintains 401(k) and other defined contribution plans thatcover substantially all employees.  Thecontributions for PSCo were approximately $6.4 million in 2009, $6.1 million in2008 and $7.9 million in 2007.

 

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**Postretirement Health CareBenefits**

** **

Xcel Energy, whichincludes PSCo, has a contributory health and welfare benefit plan that provideshealth care and death benefits to most retirees.  Employees of the former New Century Energies, Inc.(NCE) who retired in 2002 continue to receive employer-subsidized health carebenefits.  Nonbargaining employees of theformer NCE, who retired after June 30, 2003, are eligible to participatein the Xcel Energy health care program with no employer subsidy.

 

In1993, Xcel Energy and PSCo adopted accounting guidance regarding othernon-pension postretirement benefits and elected to amortize the unrecognizedaccumulated postretirement benefit obligation (APBO) on a straight-line basisover 20 years.

 

Regulatory agencies fornearly all retail and wholesale utility customers have allowed rate recovery ofaccrued postretirement benefit costs. PSCo transitioned to full accrual accounting for postretirement benefitcosts between 1993 and 1997, consistent with the accounting requirements forrate-regulated enterprises.  The Coloradojurisdictional postretirement benefit costs deferred during the transitionperiod are being amortized to expense on a straight-line basis over the 15-yearperiod from 1998 to 2012.

 

***Plan Assets —***Certain stateagencies that regulate Xcel Energy’s utility subsidiaries also have issuedguidelines related to the funding of postretirement benefit costs.  PSCo is required to fund postretirementbenefit costs in irrevocable external trusts that are dedicated to the paymentof these postretirement benefits.  Also,a portion of the assets contributed on behalf of nonbargaining retirees hasbeen funded into a sub-account of the Xcel Energy pension plans.  These assets are invested in a mannerconsistent with the investment strategy for the pension plan.

 

XcelEnergy and PSCo base the investment-return assumption for the postretirementhealth care fund assets on expected long-term performance for each of theinvestment types included in the asset portfolio.  The assets are invested in a portfolioaccording to Xcel Energy’s and PSCo’s return, liquidity and diversificationobjectives to provide a source of funding for plan obligations and minimize thenecessity of contributions to the plan, within appropriate levels of risk.  The principal mechanism for achieving theseobjectives is the allocation of assets to selected asset classes, given thelong-term risk, return, and liquidity characteristics of each particular assetclass.  There were no significant concentrationsof risk in any particular industry, index, or entity.  Investment-return volatility is notconsidered to be a material factor in postretirement health care costs.

 

Thefollowing table presents, for each of the fair value hierarchy levels, postretirementbenefit plan assets that are measured at fair value as of Dec. 31, 2009:

 
| **(Thousands of Dollars)**                | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-----------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|-----------|------------|
| Cash equivalents                                    |       | $           | —     |        | $          | 165,291     |       | $         | —     |   | $ | 165,291 |   |
| Short term  investments                             |       | —      |       | 2,226       |       | —      |       | 2,226     |       |
| Derivatives                                         |       | —      |       | 5,937       |       | —      |       | 5,937     |       |
| Government  securities                              |       | —      |       | 1,538       |       | —      |       | 1,538     |       |
| Corporate bonds                                     |       | —      |       | 60,416      |       | —      |       | 60,416    |       |
| Asset-backed &  mortgage-backed securities |       | —      |       | —      |       | 55,371      |       | 55,371    |       |
| Preferred stock                                     |       | —      |       | 540         |       | —      |       | 540       |       |
| Registered  investment companies (mutual funds)     |       | —      |       | 89,296      |       | —      |       | 89,296    |       |
| Securities  lending collateral obligation and other |       | —      |       | 4,074       |       | —      |       | 4,074     |       |
| Total                                               |       | $           | —     |        | $          | 329,318     |       | $         | 55,371     |   | $ | 384,689 |   |

 

Thefollowing table presents the changes in Level 3 postretirement benefit planassets for the year ended Dec. 31, 2009:

 
| **(Thousands of Dollars)**                | ** ** | **Jan. 1,  2009** | ** ** | **Realized  and  Unrealized Gains** | ** ** | **Purchases,  Issuances, and  Settlements (net)** | ** ** | **Dec. 31,  2009** | ** ** |
|-----------------------------------------------------|------------|------------------------|------------|-------------------------------------|------------|---------------------------------------------------|------------|-------------------------|------------|
| Asset-backed &  mortgage-backed securities |       | $                      | 78,693     |                                | $          | 4,051                                             |       | $                       | (27,373    | ) | $ | 55,371 |   |
|                                                     |            |                        |            |                                     |            |                                                   |            |                         |            |  |  |  |  |

 

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***Benefit Obligations***— A comparison of the actuarially computed benefitobligation and plan assets, on a combined basis, is presented in the followingtable:

 
| **(Thousands of Dollars)**                                                                                           | ** ** | **2009**            | ** ** | **2008**            | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|---------------------|------------|
| **Change in Projected Benefit Obligation:**                                                                                    |       |                |       |                |       |
| Obligation  at Jan. 1                                                                                                     |       | $                   | 794,597    |                | $          | 830,315 |   |
| Service  cost                                                                                                                  |       | 4,665               |       | 5,350               |       |
| Interest  cost                                                                                                                 |       | 50,412              |       | 51,047              |       |
| Medicare  subsidy reimbursements                                                                                               |       | 3,226               |       | 6,178               |       |
| Amendments                                                                                                                     |       | (27,407             | )          | —              |       |
| Plan  participants’ contributions                                                                                         |       | 13,786              |       | 13,892              |       |
| Actuarial  gain                                                                                                                |       | (47,446             | )          | (46,827             | )          |
| Benefit  payments                                                                                                              |       | (62,931             | )          | (65,358             | )          |
| Obligation  at Dec. 31                                                                                                    |       | $                   | 728,902    |                | $          | 794,597 |   |
|                                                                                                                           |       |                |       |                |       |
| **Change in Fair Value of Plan Assets:**                                                                                       |       |                |       |                |       |
| Fair  value of plan assets at Jan. 1                                                                                      |       | $                   | 299,566    |                | $          | 427,459 |   |
| Actual  return (loss) return on plan assets                                                                                    |       | 72,101              |       | (132,226            | )          |
| Plan  participants’ contributions                                                                                         |       | 13,786              |       | 13,892              |       |
| Employer  contributions                                                                                                        |       | 62,167              |       | 55,799              |       |
| Benefit  payments                                                                                                              |       | (62,931             | )          | (65,358             | )          |
| Fair  value of plan assets at Dec. 31                                                                                     |       | $                   | 384,689    |                | $          | 299,566 |   |
|                                                                                                                           |       |                |       |                |       |
| **Funded Status at Dec. 31:**                                                                                             |       |                |       |                |       |
| Funded  status                                                                                                                 |       | $                   | (344,213   | )                   | $          | (495,031 | ) |
| Current  liabilities                                                                                                           |       | (2,240              | )          | (4,928              | )          |
| Noncurrent  liabilities                                                                                                        |       | (341,973            | )          | (490,103            | )          |
| Net  amounts recognized on consolidated balance sheets                                                                         |       | $                   | (344,213   | )                   | $          | (495,031 | ) |
|                                                                                                                           |       |                |       |                |       |
| **PSCo Amounts Not Yet Recognized as Components of Net  Periodic Cost:**                                                       |       |                |       |                |       |
| Net  loss                                                                                                                      |       | $                   | 110,766    |                | $          | 181,157 |   |
| Prior  service credit                                                                                                          |       | (25,262             | )          | (1,757              | )          |
| Transition  obligation                                                                                                         |       | 33,797              |       | 44,801              |       |
| Total                                                                                                                          |       | $                   | 119,301    |                | $          | 224,201 |   |
|                                                                                                                           |       |                |       |                |       |
| **Amounts Related to the Funded Status of the Plans Have Been  Recorded as****Follows Based Upon Expected Recovery in Rates:** |       |                |       |                |       |
| Regulatory  assets                                                                                                             |       | 119,301             |       | 224,201             |       |
| Total                                                                                                                          |       | $                   | 119,301    |                | $          | 224,201 |   |
|                                                                                                                           |       |                |       |                |       |
| PSCo  accrued benefit liability recorded                                                                                       |       | 148,022             |       | 254,003             |       |
|                                                                                                                           |       |                |       |                |       |
| **Measurement Date**                                                                                                           |       | Dec. 31,  2009 |       | Dec. 31,  2008 |       |
|                                                                                                                           |       |                |       |                |       |
| **Significant Assumptions Used to Measure Benefit  Obligations:**                                                              |       |                |       |                |       |
| Discount  rate for year-end valuation                                                                                          |       | 6.00                | %          | 6.75                | %          |
| Mortality  table                                                                                                               |       | RP                  | 2000       |                | RP         | 2000 |   |
|                                                                                                                                |            |                     |            |                     |            |  |  |  |  |

 

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Effective Dec. 31,2009, Xcel Energy and PSCo reduced the initial medical trend assumption from7.4 percent to 6.8 percent.  Theultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reachedis three years.  Xcel Energy and PSCobase the medical trend assumption on the long-term cost inflation expected inthe health care market, considering the levels projected and recommended byindustry experts, as well as recent actual medical cost increases experiencedby the retiree medical plan.

 

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

 
| **(Thousands of Dollars)**                                            |   |    |   |
|---------------------------------------------------------------------------------|--------|---------|--------|
| 1-percent  increase in APBO components of Dec. 31, 2009                    |   | $       | 45,056 |   |
| 1-percent  decrease in APBO components of Dec. 31, 2009                    |   | (38,149 | )      |
| 1-percent  increase in service and interest components of the net periodic cost |   | 4,484   |   |
| 1-percent  decrease in service and interest components of the net periodic cost |   | (3,724  | )      |
|                                                                                 |        |         |        |  |

 

***Cash Flows —***The postretirement health care plans have no fundingrequirements under income tax and other retirement-related regulations otherthan fulfilling benefit payment obligations, when claims are presented andapproved under the plans.  Additionalcash funding requirements are prescribed by certain state and federal rateregulatory authorities, as discussed previously.  Xcel Energy, which includesPSCo, contributed $62.2 million during 2009 and $55.6 million in 2008 andexpects to contribute approximately $45.4 million during 2010.

 

***Plan Amendments —***The decrease inthe projected benefit obligation for the plan amendment is due to a change inthe medical experience rate resulting from negotiations with the PSCoBargaining Postretirement Health Care Plan.

 

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

 
| **(Thousands of Dollars)**                              | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Service  cost                                                     |       | $        | 4,665      |     | $          | 5,350    |       | $ | 5,813 |   |
| Interest  cost                                                    |       | 50,412   |       | 51,047   |       | 50,475   |       |
| Expected  return on plan assets                                   |       | (22,775  | )          | (31,851  | )          | (30,401  | )          |
| Amortization  of transition obligation                            |       | 14,444   |       | 14,577   |       | 14,577   |       |
| Amortization  of prior service cost                               |       | (2,726   | )          | (2,175   | )          | (2,178   | )          |
| Amortization  of net loss                                         |       | 19,329   |       | 11,498   |       | 14,198   |       |
| Net  periodic postretirement benefit cost                         |       | 63,349   |       | 48,446   |       | 52,484   |       |
| **PSCo:**                                                         |       |     |       |     |       |     |       |
| Net  periodic postretirement benefit cost recognized              |       | 40,277   |       | 26,989   |       | 28,661   |       |
| Additional  cost recognized due to effects of regulation          |       | 3,891    |       | 3,891    |       | 3,891    |       |
| Net  benefit cost recognized for financial reporting              |       | $        | 44,168     |     | $          | 30,880   |       | $ | 32,552 |   |
|                                                              |       |     |       |     |       |     |       |
| **Significant Assumptions Used to Measure Costs**:                |       |     |       |     |       |     |       |
| Discount  rate for year-end valuation                             |       | 6.75     | %          | 6.25     | %          | 6.00     | %          |
| Expected  average long-term rate of return on assets (before tax) |       | 7.50     |       | 7.50     |       | 7.50     |       |

 

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**Projected BenefitPayments**

 

The following table liststhe projected benefit payments for the pension and postretirement benefitplans.

 
| **(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** | ** ** |
|--------------------------------------|------------|------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------------------------------|------------|--------------------------------------------------------------------|------------|
| 2010                                 |       | $                                        | 238,929    |                                                                 | $          | 58,738                                        |       | $                                                                  | 4,901      |   | $ | 53,837 |   |
| 2011                                 |       | 230,833                                  |       | 60,202                                                               |       | 5,184                                         |       | 55,018                                                             |       |
| 2012                                 |       | 234,256                                  |       | 60,665                                                               |       | 5,529                                         |       | 55,136                                                             |       |
| 2013                                 |       | 237,817                                  |       | 60,785                                                               |       | 5,841                                         |       | 54,944                                                             |       |
| 2014                                 |       | 244,160                                  |       | 61,260                                                               |       | 6,075                                         |       | 55,185                                                             |       |
| 2015-2019                            |       | 1,256,824                                |       | 313,040                                                              |       | 33,598                                        |       | 279,442                                                            |       |
|                                      |            |                                          |            |                                                                      |            |                                               |            |                                                                    |            |  |  |  |  |

 

**10.   Other Income(Expense), Net**

 

Other income (expense),net for the years ended Dec. 31 consisted of the following:

 
| **(Thousands of Dollars)** | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Interest  income                     |       | $        | 3,247      |     | $          | 10,283   |       | $ | 9,876 |   |
| Other  nonoperating income           |       | 3,192    |       | 2,954    |       | 2,373    |       |
| Insurance  policy (expenses) income  |       | (1,348   | )          | 3,515    |       | (14,642  | )          |
| Other  nonoperating expenses         |       | (395     | )          | (4       | )          | (7       | )          |
| Other  income (expense), net         |       | $        | 4,696      |     | $          | 16,748   |       | $ | (2,400 | ) |

 

**11.    Derivative Instruments**

** **

EffectiveJan. 1, 2009, PSCo adopted new guidance on disclosures about derivativeinstruments and hedging activities contained in *ASC 815 Derivatives and Hedging*, which requires additionaldisclosures regarding why an entity uses derivative instruments, the volume ofan entity’s derivative activities, the fair value amounts recorded to theconsolidated balance sheet for derivatives, the gains and losses on derivativeinstruments included in the consolidated statement of income or deferred, andinformation regarding certain credit-risk-related contingent features inderivative contracts.

 

PSCoenters into derivative instruments, including forward contracts, futures, swapsand options, for trading purposes and to reduce risk in connection with changesin interest rates, utility commodity prices and vehicle fuel prices.  See additional information pertaining to thevaluation of derivative instruments in Note 13 to the consolidated financialstatements.

 

***Interest Rate Derivatives —***PSCo entersinto various instruments that effectively fix the interest payments on certainfloating rate debt obligations or effectively fix the yield or price on aspecified benchmark interest rate for a specific period.  These derivative instruments are generallydesignated as cash flow hedges for accounting purposes.

 

AtDec. 31, 2009, accumulated other comprehensive income related to interestrate derivatives included $1.5 million of net gains expected to be reclassifiedinto earnings during the next 12 months as the related hedged interestrate transactions impact earnings.

 

***Commodity Derivatives —***PSCo entersinto derivative instruments to manage variability of future cash flows fromchanges in commodity prices in its electric and natural gas operations, as wellas for trading purposes.  This couldinclude the purchase or sale of energy or energy-related products, natural gasto generate electric energy, gas for resale, and vehicle fuel.

 

AtDec. 31, 2009, PSCo had vehicle fuel contracts designated as cash flowhedges extending through December 2012. PSCo also enters into derivative instruments that mitigate commodityprice risk on behalf of electric and natural gas customers but are notdesignated as qualifying hedging transactions. Changes in thefair value of non-trading commodity derivative instruments are recorded inother comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset orliability is based on commission approved regulatory recovery mechanisms.  PSCo recorded immaterial amounts to incomerelated to the ineffectiveness of cash flow hedges for the years ended Dec. 31,2009 and 2008.

 

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AtDec. 31, 2009, accumulated other comprehensive income related to vehiclefuel cash flow hedges included $1.2 million of net losses expected to bereclassified into earnings during the next 12 months as the hedgedtransactions occur.

 

Additionally, PSCo enters into commodityderivative instruments for trading purposes not directly related to commodityprice risks associated with serving its electric and natural gascustomers.  Changes in the fair value ofthese commodity derivatives are recorded in income subject to applicablecustomer margin-sharing mechanisms.

 

PSCo had no derivativeinstruments designated as fair value hedges during the year ended Dec. 31,2009.  Therefore, no gains or losses fromfair value hedges or related hedged transactions were recognized for theperiod.

 

Thefollowing table shows the major components of derivative instruments valuationin the consolidated balance sheets:

 
| ** **                            | ** ** | **2009**             | ** ** | **2008**             | ** ** |
|---------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                            | ** ** | **Derivative**       | ** ** | **Derivative**       | ** ** | **Derivative** | ** ** | **Derivative** | ** ** |
| ** **                            | ** ** | **Instruments**      | ** ** | **Instruments**      | ** ** | **Instruments** | ** ** | **Instruments** | ** ** |
| ** **                            | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** | **Valuation -** | ** ** |
| **(Thousands of Dollars)**  | ** ** | **Assets**           | ** ** | **Liabilities**      | ** ** | **Assets** | ** ** | **Liabilities** | ** ** |
| Long-term  purchased power agreements |       | $                    | 118,740    |                 | $          | 55,936 |   | $ | 137,334 |   | $ | 66,986 |   |
| Commodity  derivatives                |       | 14,628               |       | 11,936               |       | 4,993 |   | 23,916 |   |
| Total                                 |       | $                    | 133,368    |                 | $          | 67,872 |   | $ | 142,327 |   | $ | 90,902 |   |

 

In2003, as a result ofimplementing new guidance on the normal purchase exception for derivativeaccounting contained in *ASC 815 Derivatives andHedging*, PSCo began recording several long-term purchased power agreements atfair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered throughnormal regulatory recovery mechanisms in the respective jurisdictions, thechanges in fair value for these contracts were offset by regulatory assets andliabilities.  During 2006, PSCo qualifiedthese contracts under the normal purchase exception.  Based on this qualification, the contractsare no longer adjusted to fair value and the previous carrying value of thesecontracts will be amortized over the remaining contract lives along with theoffsetting regulatory assets and liabilities.

 

***Financial Impact of Qualifying CashFlow Hedges —***The impact of qualifying interest rate and vehiclefuel cash flow hedges on PSCo’s accumulated other comprehensive income,included as a component of common stockholder’s equity, is detailed in thefollowing tables:

 
| **(Thousands of Dollars)**                                                          | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Accumulated  other comprehensive income related to cash flow hedges at Jan. 1            |       | $        | 7,628      |     | $          | 12,447   |       | $ | 12,614 |   |
| After-tax  net unrealized gains (losses) related to derivatives accounted for as hedges       |       | 315      |       | (3,294   | )          | 1,352    |       |
| After-tax  net realized losses (gains) on derivative transactions reclassified into  earnings |       | 158      |       | (1,525   | )          | (1,519   | )          |
| Accumulated  other comprehensive income related to cash flow hedges at Dec. 31           |       | $        | 8,101      |     | $          | 7,628    |       | $ | 12,447 |   |

 

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**The following table details thefair value of commodity derivatives recorded to derivative instrumentsvaluation in the consolidated balance sheet, by category:**

 
| ** **                                   | ** ** | **Dec. 31,  2009** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|
| ** **                                   | ** ** | ** **              | ** ** | ** ** | ** ** | **Derivative** | ** ** |
| ** **                                   | ** ** | ** **              | ** ** | **Counterparty** | ** ** | **Instruments** | ** ** |
| **(Thousands of Dollars)**         | ** ** | **Fair  Value**         | ** ** | **Netting****(a)** | ** ** | **Valuation** | ** ** |
| **Current derivative assets**                |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | $                       | 3,367      |   | $ | (2,121 | ) | $ | 1,246 |   |
| Natural  gas commodity                       |       | 8,753                   |       | 111 |   | 8,864 |   |
| Total  current derivative assets             |       | $                       | 12,120     |   | $ | (2,010 | ) | $ | 10,110 |   |
|                                         |       |                    |       |   |   |   |   |
| **Noncurrent derivative assets**             |       |                    |       |   |   |   |   |
| Derivatives  designated as cash flow hedges: |       |                    |       |   |   |   |   |
| Vehicle  fuel and other commodity            |       | $                       | 69         |   | $ | — |   | $ | 69 |   |
| Other  derivative instruments:               |       |                    |       |   |   | — |   |
| Trading  commodity                           |       | 3,048                   |       | 677 |   | 3,725 |   |
| Natural  gas commodity                       |       | 476                     |       | 248 |   | 724 |   |
|                                         |       | 3,524                   |       | 925 |   | 4,449 |   |
| Total  noncurrent derivative assets          |       | $                       | 3,593      |   | $ | 925 |   | $ | 4,518 |   |

 
| ** **                                   | ** ** | **Dec. 31,  2009** | ** ** |
|----------------------------------------------|------------|-------------------------|------------|
| ** **                                   | ** ** | ** **              | ** ** | ** ** | ** ** | **Derivative** | ** ** |
| ** **                                   | ** ** | ** **              | ** ** | **Counterparty** | ** ** | **Instruments** | ** ** |
| **(Thousands of Dollars)**         | ** ** | **Fair  Value**         | ** ** | **Netting****(a)** | ** ** | **Valuation** | ** ** |
|                                         |       |                    |       |   | ** ** | ** ** | ** ** |
| **Current derivative liabilities**           |       |                    |       |   |   |   |   |
| Derivatives  designated as cash flow hedges: |       |                    |       |   |   |   |   |
| Vehicle  fuel and other commodity            |       | $                       | 1,338      |   | $ | — |   | $ | 1,338 |   |
|                                         |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | 4,391                   |       | (2,591 | ) | 1,800 |   |
| Natural  gas commodity                       |       | 6,089                   |       | 111 |   | 6,200 |   |
|                                         |       | 10,480                  |       | (2,480 | ) | 8,000 |   |
| Total  current derivative liabilities        |       | $                       | 11,818     |   | $ | (2,480 | ) | $ | 9,338 |   |
|                                         |       |                    |       |   |   |   |   |
| **Noncurrent derivative liabilities**        |       |                    |       |   |   |   |   |
| Other  derivative instruments:               |       |                    |       |   |   |   |   |
| Trading  commodity                           |       | $                       | 1,373      |   | $ | 675 |   | $ | 2,048 |   |
| Natural  gas commodity                       |       | 302                     |       | 248 |   | 550 |   |
| Total  noncurrent derivative liabilities     |       | $                       | 1,675      |   | $ | 923 |   | $ | 2,598 |   |

 

----

(a)             *ASC 815, Derivatives and Hedging*,permits the netting of receivables and payables for derivatives and relatedcollateral amounts when a legally enforceable master netting agreement existsbetween PSCo and a counterparty.  Amaster netting agreement is an agreement between two parties who have multiplecontracts with each other that provides for the net settlement of all contractsin the event of default on or termination of any one contract.

 

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Thefollowing table details the impact of derivative activity during the year endedDec. 31, 2009, on other comprehensive income, regulatory assets andliabilities, and income:

 
| ** **                                     | ** ** | **Fair  Value Changes Recognized** | ** ** | **Pre-Tax  Amounts Reclassified into** | ** ** | **Pre-Tax**         | ** ** |
|------------------------------------------------|------------|------------------------------------|------------|----------------------------------------|------------|---------------------|------------|
| ** **                                     | ** ** | **During  the Period in:**         | ** ** | **Income  During the Period from:**    | ** ** | **Gains  (Losses)** | ** ** |
| ** **                                     | ** ** | **Other**                          | ** ** | **Regulatory**                         | ** ** | **Other**           | ** ** | **Regulatory** | ** ** | **Recognized** | ** ** |
| ** **                                     | ** ** | **Comprehensive**                  | ** ** | **Assets  and**                        | ** ** | **Comprehensive**   | ** ** | **Assets  and** | ** ** | **During  the Period** | ** ** |
| **(Thousands of Dollars)**           | ** ** | **Income  (Loss)**                 | ** ** | **Liabilities**                        | ** ** | **Income  (Loss)**  | ** ** | **Liabilities** | ** ** | **in  Income** | ** ** |
| **Derivatives designated as cash flow hedges** |       |                               | ** ** | ** **                             |       |                | ** ** | ** ** |   |   |   |
| Interest  rate                                 |       | $                                  | (632       | )                                      | $          | —              |       | $ | (2,361 | )(d) | $ | — |   | $ | — |   |
| Natural  gas commodity                         |       | —                             |       | (14,641                                | )          | —              |       | 66,311 | (c) | (22,243 | )(c) |
| Vehicle  fuel and other commodity              |       | 1,140                              |       | —                                 |       | 2,624               | (a)        | — |   | — |   |
| Total                                          |       | $                                  | 508        |                                   | $          | (14,641             | )          | $ | 263 |   | $ | 66,311 |   | $ | (22,243 | ) |
|                                           |       |                               |       |                                   |       |                |       |   |   |   |   |
| **Other derivative instruments**               |       |                               |       |                                   |       |                |       |   |   |   |   |
| Trading  commodity                             |       | $                                  | —     |                                   | $          | —              |       | $ | — |   | $ | — |   | $ | 2,009 | (b) |
| Natural  gas commodity                         |       | —                             |       | 3,880                                  |       | —              |       | 8,190 | (c) | — |   |
| Total                                          |       | $                                  | —     |                                   | $          | 3,880               |       | $ | — |   | $ | 8,190 |   | $ | 2,009 |   |

 

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(a)             Recorded to other operating andmaintenance expenses.

(b)            Recorded to electric operatingrevenues.  Portions of these gains andlosses are shared with electric customers through margin-sharing mechanisms anddeducted from gross income, as appropriate.

(c)             Recorded to cost of natural gassold and transported; these derivative settlement gains and losses are sharedwith natural gas customers through purchased natural gascost-recovery mechanisms, and reclassifiedout of income as regulatory assets or liabilities, as appropriate.

(d)            Recorded to interest charges.

 

AtDec. 31, 2009, commodity derivatives recorded to derivative instrumentsvaluation included derivative contracts with gross notional amounts ofapproximately 3,559,000 megawatt (MW) hours of electricity, 45,352,000 MMBtu ofnatural gas, and 1,559,000 gallons of vehicle fuel.  These amounts reflect the gross notionalamounts of futures and forwards, and are not reflective of net positions in theunderlying commodities.  Notional amountsfor options are also included on a gross basis, but are weighted for theprobability of exercise.

 

***Credit Related Contingent Features******—***Contract provisionsof PSCo’s derivative instruments may require the posting of collateral orsettlement of the contracts for various reasons, including if PSCo is unable tomaintain its credit rating.  If thecredit rating of PSCo at Dec. 31, 2009 were downgraded below investmentgrade, contracts underlying $0.6 million of derivative instruments in aliability position would have required PSCo to post collateral or settleapplicable contracts, which would have resulted in payments to counterpartiesof $3.4 million.  At Dec. 31, 2009,there was no collateral posted on these specific contracts.

 

Certainof PSCo’s derivative instruments are also subject to contract provisions thatcontain adequate assurance clauses. These provisions allow counterparties to seek performance assurance,including cash collateral, in the event that PSCo’s ability to fulfill itscontractual obligations is reasonably expected to be impaired.  As of Dec. 31, 2009, PSCo had nocollateral posted related to adequate assurance clauses in derivative contracts.

 

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**12.    Financial Instruments**

** **

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

 
| ** **                                 | ** ** | **2009**             | ** ** | **2008**        | ** ** |
|--------------------------------------------|------------|----------------------|------------|-----------------|------------|
| **(Thousands of Dollars)**       | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| Other  investments                         |       | $                    | 8          |            | $          | 8 |   | $ | 2 |   | $ | 2 |   |
| Long-term  debt, including current portion |       | 2,828,952            |       | 3,050,249       |       | 2,490,761 |   | 2,654,256 |   |
|                                            |            |                      |            |                 |            |  |  |  |  |  |  |  |  |

 

The fair value of cashand cash equivalents, notes and accounts receivable and notes and accountspayable are not materially different from their carrying amounts.  The fair value of PSCo’s other investments isestimated based on quoted market prices for those or similar investments.  The fair value of PSCo’s long-term debt isestimated based on the quoted market prices for the same or similar issues orthe current rates for debt of the same remaining maturities and credit quality.

 

The fair value estimatespresented are based on information available to management as of Dec. 31,2009 and 2008.  These fair valueestimates have not been comprehensively revalued for purposes of theseconsolidated financial statements since that date and current estimates of fairvalues may differ significantly.

 

**Letters of Credit**

** **

PSCo use letters ofcredit, generally with terms of one year, to provide financial guarantees forcertain operating obligations.  At Dec. 31,2009 and 2008, there were $4.6 million and $4.9 million of letters of creditoutstanding.  The contract amounts ofthese letters of credit approximate their fair value and are subject to feesdetermined in the marketplace.

 

**13.    Fair Value Measurements**

** **

Effective Jan. 1,2008, PSCo adopted new guidance for recurring fair value measurements containedin *ASC 820 Fair Value Measurements and Disclosures*which provides a single definition of fair value and requires enhanceddisclosures about assets and liabilities measured at fair value.  A hierarchal framework for disclosing theobservability of the inputs utilized in measuring assets and liabilities atfair value was established by this guidance. The three levels in the hierarchy and examples of each level are asfollows:

 

Level 1 — Quoted pricesare available in active markets for identical assets or liabilities as of thereported date.  The types of assets andliabilities included in Level 1 are highly liquid and actively tradedinstruments with quoted prices, such as commodity derivative contracts listedon the New York Mercantile Exchange.

 

Level 2 — Pricing inputsare other than quoted prices in active markets, but are either directly orindirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typicallyeither comparable to actively traded contracts, such as energy forwards withpricing interpolated from recent trades at a similar location, or priced withmodels using highly observable inputs, such as commodity options priced usingobservable forward prices and volatilities.

 

Level 3 — Significantinputs to pricing have little or no observability as of the reportingdate.  The types of assets andliabilities included in Level 3 are those with inputs requiring significantmanagement judgment or estimation, such as the long-term commodity priceforecasts used to determine the fair value of long-term energy forwards.

 

PSCocontinuously monitors the creditworthiness of the counterparties to itscommodity derivative contracts and assesses each counterparty’s ability toperform on the transactions set forth in the contracts.  Given this assessment, as well as anassessment of the impact of PSCo’s own credit risk when determining the fairvalue of commodity derivative liabilities, the impact of considering creditrisk was immaterial to the fair value of commodity derivative assets andliabilities presented in the consolidated balance sheets.

 

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Thefollowing tables present, for each of these hierarchy levels, PSCo’s assets andliabilities that are measured at fair value on a recurring basis:

 
| ** **                           | ** ** | **Dec. 31,  2009** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Level 1**        | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Netting** | ** ** | **Net  Balance** | ** ** |
| Commodity  derivative assets         |       | $                       | —     |   | $ | 13,192 |   | $ | 2,521 |   | $ | (1,085 | ) | $ | 14,628 |   |
| Commodity  derivative liabilities    |       | —                  |       | 11,776 |   | 1,717 |   | (1,557 | ) | 11,936 |   |
|                                      |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                           | ** ** | **Dec. 31,  2008** | ** ** |
|--------------------------------------|------------|-------------------------|------------|
| ** **                           | ** ** | ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | **Counterparty** | ** ** | ** ** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Level 1**        | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Netting** | ** ** | **Net  Balance** | ** ** |
| Commodity  derivative assets         |       | $                       | —     |   | $ | 12,607 |   | $ | 1,358 |   | $ | (8,972 | ) | $ | 4,993 |   |
| Commodity  derivative liabilities    |       | —                  |       | 55,935 |   | 1,384 |   | (33,403 | ) | 23,916 |   |
|                                      |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The following table presentsthe changes in Level 3 recurring fair value measurements for the year ended Dec. 31:

 
| ** **                                             | ** ** | **2009**         | ** ** | **2008**         | ** ** |
|--------------------------------------------------------|------------|------------------|------------|------------------|------------|
| ** **                                             | ** ** | **Commodity**    | ** ** | **Commodity**    | ** ** |
| ** **                                             | ** ** | **Derivatives,** | ** ** | **Derivatives,** | ** ** |
| **(Thousands of Dollars)**                   | ** ** | **Net**          | ** ** | **Net**          | ** ** |
| Balance  at Jan. 1                                |       | $                | (26        | )                | $          | 4,121 |   |
| Purchases,  issuances, and settlements, net            |       | (3,668           | )          | (4,396           | )          |
| Transfers  into Level 3                                |       | 579              |       | —           |       |
| Gains  (losses) recognized in earnings                 |       | 2,535            |       | (1,384           | )          |
| Gains  recognized as regulatory assets and liabilities |       | 1,384            |       | 1,633            |       |
| Balance  at Dec. 31                               |       | $                | 804        |             | $          | (26 | ) |

 

Gainson Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31,2009, include $2.6 million of net unrealized gains relating to commodityderivatives held at Dec. 31, 2009. Losses on Level 3 commodity derivatives recognized in earnings for theyear ended Dec. 31, 2008, include $0.8 million of net unrealized gainsrelating to commodity derivatives held at Dec. 31, 2008.  Realized and unrealized gains and losses oncommodity trading activities are included in electric utility revenues.  Realized and unrealized gains and losses onshort-term wholesale activities reflect the impact of regulatory recovery andare deferred as regulatory assets and liabilities.

 

**14.    Rate Matters**

** **

***Pending and Recently Concluded RegulatoryProceedings — CPUC***

*** ***

**BaseRate**

 

***PSCo 2009 Electric Rate Case***** —**In November 2008, PSCo filed a request with theCPUC to increase Colorado electric rates by $174.7 million annually, orapproximately 7.4 percent.  The ratefiling was based on a 2009 forecast test year, an electric rate base of$4.2 billion, a requested ROE of 11.0 percent and an equity ratio of58.08 percent.  PSCo’s requestincluded a return of approximately $40 million for CWIP associated withincremental expenditures on the Comanche Unit 3 since Jan. 1, 2007.  PSCo does not record AFUDC income for themonths this return is actually received from customers.

 

InMarch 2009, PSCo filed rebuttal testimony and revised its rate increaserequest to $159.3 million to reflect updated data. In May 2009, the CPUCapproved a blackbox settlement agreement which provided for an overall $112.2million increase in base rates.  Thesettlement provides that incremental CWIP not included in existing rates forthe Comanche Unit 3 be removed from rate base and that PSCo would be allowed tocontinue to record AFUDC income on this balance until the Comanche Unit 3 isplaced into service.  New rates went intoeffect on July 1, 2009.

 

***PSCo 2010 Electric Rate Case***** —**In May 2009, PSCo filed with the CPUC a requestto increase Colorado electric rates by $180.2 million, or 6.8 percent,effective in 2010.  The request was based on a 2010 forecast test year, an11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05percent,   In October 2009, PSCofiled rebuttal testimony and revised the requested rate increase to $177.4million.

 

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In November 2009,PSCo reached a settlement agreement with certain intervenors.  The settlement included an electric rateincrease of approximately $136 million, effective Jan. 1, 2010.  The settlement was based on a 10.5 percentROE and reflects PSCo’s actual capital structure.  The settlement was based on an historic testyear, adjusted for 2010 known and measurable changes related to plantinvestment as well as certain operating costs.

 

In December 2009, the CPUC approved a rateincrease of approximately $128.3 million. The difference between the settlement rate increase and the approvedamount was primarily related to adjustments related to rate base for non-majorprojects and an adjustment to interest on long-term debt.

 

In December 2009,due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’sproposal to phase in the approved electric rate increase to reflect the actualcost of service.  This decision is notexpected to have a material impact on PSCo or Xcel Energy’s financial results.  Under the plan the following increases will beimplemented:

 

·                  A rate increase of $67 million wasimplemented on Jan. 1, 2010.  Theadjustments to the rate increase, as a result of the delay of the in-servicedate of Comanche Unit 3, include reduced O&M, property taxes, the impact ofa delay in changes to jurisdictional allocators and depreciation expenses.

·                  Base rates will increase to $121 million,once Comanche Unit 3 goes into service (currently expected by the end ofthe first quarter of 2010).

·                  Finally, base rates will increase to$128.3 million on Jan. 1, 2011 to reflect 2011 property taxes.

 

Several parties,including the Office of Consumer Counsel, have filed motions forreconsideration.  The CPUC has deniedthose requests that would change the initial order approving the rate increase,with the exception of PSCo’s request to not include long-term debt interest inthe working capital calculation.  TheCPUC will reconsider PSCo’s request after parties have filed additionalcomments.  A written order is pending.

 

***Unreasonable Ratesfor Natural Gas Formal Complaint —***In July 2009, the trialadvocacy staff of the CPUC proposed a formal draft complaint against PSCo forunjust and unreasonable rates for natural gas service associated with earningsin excess of PSCo’s authorized return that occurred in 2008.  In January 2010, the CPUC opened aproceeding and assigned this matter to an ALJ.

 

The procedural schedule inthe case has been set as follows:

 

·                  Direct testimony of CPUC staff  on May 10, 2009;

·                  PSCo answer testimony on June 28, 2010;

·                  Staff rebuttal testimony on July 19, 2010;

·                  Surrebuttal testimony on Aug. 9, 2010; and

·                  Hearings on Aug. 23 - 27, 2010.

 

***TCA Rider —***PSCo filed itsannual update to the TCA rider in November 2008, and new rates went intoeffect on Jan. 1, 2009, to recover approximately $18.0 million on anannual basis until the rates in the 2009 rate case take effect.  Coincident with the implementation of newelectric rates on July 1, 2009, approximately $16.0 million from the TCArider were included in base rates with a corresponding reduction in the TCArider.

 

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***Renewable Energy Credit (REC) Sharing Settlement******—***In August 2009, PSCo filed anapplication seeking approval of treatment of margins associated with certainsales of Colorado RECs bundled with energy into California.  PSCo’s requestsought 45 percent of the margins on these specific transactions for both thecustomers and PSCo with the remaining ten percent being used to fund a programto develop carbon offset projects and expertise.  On Jan. 20, 2010,PSCo, the Office of Consumer Council, the CPUC staff, the Colorado governor’senergy office and Western Resource Advocates entered into a unanimoussettlement in this case.  The settlement establishes a pilot program anddefines certain margin splits during this pilot period.  The settlementprovides that 10 percent of margins will go to carbon offsets, 40 percent ofthe first $10 million in margins, 35 percent of the next $20 million and 30percent of all remaining margins will go to PSCo with all remaining marginsgoing to Colorado retail the customers as a credit toward renewable energyprojects.  The unanimous settlement also clarified that margins associatedwith RECs bundled with Colorado energy would be shared 20 percent to PSCo and80 percent to customers and margins associated with sales of stand-alonerenewable energy credits without energy would be credited 100 percent tocustomers.  It is expected that PSCo will file an application byAug. 31, 2010 for future treatment of margins from transactionsfor RECs bundled with energy after the end of the pilot program.  On Feb. 18,2010, the CPUC approved the settlement.

 

***Pending and RecentlyConcluded Regulatory Proceedings — FERC***

*** ***

***Pacific Northwest FERC Refund Proceeding —***In July 2001,the FERC ordered a preliminary hearing to determine whether there may have beenunjust and unreasonable charges for spot market bilateral sales in the PacificNorthwest for the period Dec. 25, 2000 through June 20, 2001.  PSCo supplied energy to the Pacific Northwestmarkets during this period and has been a participant in the hearings.  In September 2001, the presiding ALJconcluded that prices in the Pacific Northwest during the referenced periodwere the result of a number of factors, including the shortage of supply,excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concludedthat the prices in the Pacific Northwest markets were not unreasonable orunjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to requestadditional evidence.  Parties haveclaimed that the total amount of transactions with PSCo subject to refund is$34 million.  In June 2003, theFERC issued an order terminating the proceeding without ordering furtherproceedings.  Certain purchasers filedappeals of the FERC’s orders in this proceeding with the U. S. Court of Appealsfor the Ninth Circuit.

 

Inan order issued in August 2007, the Court of Appeals remanded theproceeding back to the FERC.  The Courtof Appeals also indicated that the FERC should consider other rulingsaddressing overcharges in the California organized markets.  The Court of Appeals denied a petition forrehearing in April 2009, and the mandate was issued.  The FERC hasyet to act on this order on remand; currently, certain motions concerningprocedures on remand are pending before the FERC.

 

***Wholesale Rate Case***— In 2009,PSCo proposed to increase Colorado wholesale rates by $30 million based on a12.5 percent ROE, a 58 percent equity ratio and an electric production rate baseof $315 million.  PSCo has requested that FERC suspend action on thefiling to allow time for settlement negotiations.  Settlement discussions with PSCo’s wholesalecustomers are continuing.  PSCo expectsrates subject to refund to go into effect in the second quarter of 2010.

 

**15.    Commitments and Contingent Liabilities**

** **

***Capital Commitments —***As of Dec. 31, 2009, the estimated cost of thecapital expenditure programs and other capital requirements of PSCo isapproximately $610 million in 2010, $600 million in 2011 and $710 million in2012.

 

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

 

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***Fuel Contracts*****— PSCo has contracts providing for the purchase anddelivery of a significant portion of its current coal and natural gasrequirements.  These contracts expire invarious years between 2010 and 2040.  Inaddition, PSCo may be required to pay additional amounts depending on actualquantities shipped under these agreements. The potential risk of loss, in the form of increased costs from marketprice changes in fuel, is mitigated through the cost-rate adjustmentmechanisms, which provide for pass through of most fuel, storage andtransportation costs to customers.

 

The estimated minimumpurchases for PSCo under these contracts as of Dec. 31, 2009, are asfollows:

 
| **(Millions  of Dollars)**        | ** ** | ** ** | ** ** |
|----------------------------------------|------------|------------|------------|
| Coal                                   |       | $          | 493.4      |   |
| Natural  gas supply                    |       | 723.2      |       |
| Gas  storage & transportation |       | 1,977.5    |       |
|                                        |            |            |            |  |

** **

***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.  PSCo has various pay-for-performancecontracts with expiration dates through the year 2033.  In general, these contracts provide forcapacity payments, subject to meeting certain contract obligations and energypayments based on actual power taken under the contracts.  Certain contractual payment obligations areadjusted based on indices.  However, theeffects of these price adjustments are mitigated through cost-of-energy rateadjustment mechanisms.

 

At Dec. 31, 2009,the estimated future payments for capacity, accounted for as executorycontracts, that PSCo is obligated to purchase, subject to availability, were asfollows:

 
| **(Millions of Dollars)** | ** ** | ** ** | ** ** |
|-------------------------------------|------------|------------|------------|
| 2010                                |       | $          | 338.1      |   |
| 2011                                |       | 328.6      |       |
| 2012                                |       | 271.2      |       |
| 2013                                |       | 204.7      |       |
| 2014                                |       | 148.0      |       |
| 2015  and thereafter                |       | 799.8      |       |
| Total                               |       | $          | 2,090.4    |   |

** **

***Leases*****— PSCo leases a variety of equipment andfacilities used in the normal course of business.  Three of these leases qualify as capitalleases and are accounted for accordingly. The assets and liabilities acquired under capital leases are recorded atthe lower of fair-market value or the present value of future lease paymentsand are amortized over their actual contract term in accordance with practicesallowed by regulators.

 

In1999, WYCO was formed as a joint venture between Xcel Energy and ColoradoInterstate Gas Company (CIG) to develop and lease natural gas pipeline,storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO.  In 2009, WYCO’s Totem gas storage facilitieswere placed in service.  WYCO leases thefacilities to CIG, and CIG operates the facilities, providing natural gasstorage services to PSCo under a service arrangement that commenced on July 1,2009.

 

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PSCoaccounts for its Totem natural gas storage service arrangement with CIG as acapital lease in accordance with the authoritative guidance on leaseaccounting.  As a result, PSCo has a$141.1 million capital lease obligation, net of amortization, recorded for thearrangement as of Dec. 31, 2009.  WYCOis expected to incur approximately $14 million of additional constructioncosts, 50 percent of which will be paid by Xcel Energy, to finalizeconstruction and make Totem operational at full storage capacity.

 

Following is a summary ofassets held under capital leases:

 
| **(Millions of Dollars)**            | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------------------------|------------|----------|------------|----------|------------|
| Storage,  leaseholds and rights                |       | $        | 183.6      |     | $          | 40.5 |   |
| Gas  pipeline                                  |       | 20.7     |       | 20.7     |       |
| Property  held under capital lease             |       | 204.3    |       | 61.2     |       |
| Accumulated  depreciation                      |       | (21.3    | )          | (17.8    | )          |
| Total  property held under capital leases, net |       | $        | 183.0      |     | $          | 43.4 |   |

 

The remainder of the leases, primarilyfor office space, railcars, generating facilities, trucks, cars andpower-operated equipment are accounted for as operating leases.  Total rental expense under operating leaseobligations was approximately $80.9 million, $85.6 million and $44.6 millionfor 2009, 2008 and 2007, respectively. Included in total rental expense were purchase power agreement paymentsof $64.8 million, $67.5 million and $26.1 million in 2009, 2008 and 2007,respectively.

 

Included in the futurecommitments under operating leases are estimated future payments under purchasepower agreements that have been accounted for as operating leases in accordancewith *ASC 840 Leases*.  Future commitments under operating andcapital leases are:

 
| **(Millions of Dollars)**  | ** ** | **Other  Operating  Leases** | ** ** | **Purchase  Power  Agreement  Operating Leases****(a) (b)** | ** ** | **Total  Operating  Leases** | ** ** | **Capital  Leases** | ** ** |
|--------------------------------------|------------|------------------------------|------------|------------------------------------------------------------------|------------|------------------------------|------------|---------------------|------------|
| 2010                                 |       | $                            | 14.2       |                                                             | $          | 48.5                         |       | $                   | 62.7       |   | $ | 28.5 |   |
| 2011                                 |       | 15.6                         |       | 44.6                                                             |       | 60.2                         |       | 31.4                |       |
| 2012                                 |       | 14.5                         |       | 55.8                                                             |       | 70.3                         |       | 29.7                |       |
| 2013                                 |       | 14.0                         |       | 73.2                                                             |       | 87.2                         |       | 29.5                |       |
| 2014                                 |       | 14.1                         |       | 79.4                                                             |       | 93.5                         |       | 29.4                |       |
| Thereafter                           |       | 55.5                         |       | 757.6                                                            |       | 813.1                        |       | 633.7               |       |
| Total  minimum obligation            |       |                         |       |                                                             |       |                         |       | 782.2               |       |
| Interest  component of obligation    |       |                         |       |                                                             |       |                         |       | (599.2              | )          |
| Present  value of minimum obligation |       |                         |       |                                                             |       |                         |       | $                   | 183.0      |   |
|                                      |            |                              |            |                                                                  |            |                              |            |                     |            |  |  |  |  |

 

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(a)  Amounts notincluded in purchase power agreement estimated future payments above.

(b)  Purchase poweragreeement operating leases contractually expire through 2028.

 

**Environmental Contingencies**

 

PSCo has been, or is currently,involved with the cleanup of contamination from certain hazardous substances atseveral sites.  In many situations, PSCobelieves it will recover some portion of these costs through insurance claims.  Additionally, where applicable, PSCo ispursuing, or intends to pursue, recovery from other PRPs and through the rateregulatory process.  New and changingfederal and state environmental mandates can also create added financialliabilities for PSCo, which are normally recovered through the rate regulatoryprocess.  To the extent any costs are notrecovered through the options listed above, PSCo would be required to recognizean expense.

 

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***Site Remediation****—*PSCo must payall or a portion of the cost to remediate sites where past activities of PSCoor other parties have caused environmental contamination.  Environmental contingencies could arise fromvarious situations including sites of former MGPs operated by PSCo, itspredecessors, or other entities; and third party sites, such as landfills, towhich PSCo is alleged to be a PRP that sent hazardous materials andwastes.  At Dec. 31, 2009, theliability for the cost of remediating these sites was estimated to be $0.9million, of which $0.3 million was considered to be a current liability.

 

***Asbestos Removal*****—**Some of PSCo’sfacilities contain asbestos.  Mostasbestos will remain undisturbed until the facilities that contain it aredemolished or renovated.  PSCo hasrecorded an estimate for final removal of the asbestos as an ARO. Seeadditional discussion of AROs below.  Itmay be necessary to remove some asbestos to perform maintenance or makeimprovements to other equipment.  Thecost of removing asbestos as part of other work is immaterial and is recordedas incurred as operating expenses for maintenance projects, capitalexpenditures for construction projects or removal costs for demolitionprojects.

 

***Other Environmental Requirements***

 

***EPA GHG Endangerment Finding***— On Dec. 7, 2009, in response to theU. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007),the EPA issued its “endangerment” finding that GHG emissions endanger publichealth and welfare and that emissions from motor vehicles contribute to theGHGs in the atmosphere.  Thisendangerment finding creates a mandatory duty for the EPA to regulate GHGs fromlight duty vehicles.  The EPA hasproposed to finalize GHG efficiency standards for light duty vehiclesby spring 2010.  Thereafter, the EPA anticipatesphasing-in permit requirements and regulation of GHGs for large stationarysources, such as power plants, in calendar year 2011.

 

***Regional Haze Rules ***— In June 2005, the EPAfinalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions ofthe regional haze rule that require emission controls, known as BART, forindustrial facilities emitting air pollutants that reduce visibility by causingor contributing to regional haze.  SomePSCo generating facilities will be subject to BART requirements.

 

Statesare required to identify the facilities that will have to reduce SO2, NOx and particulate matteremissions under BART and then set BART emissions limits for thosefacilities.  In May 2006, theColorado Air Quality Control Commission (AQCC) promulgated BART regulationsrequiring certain major stationary sources to evaluate and install, operate andmaintain BART to make reasonable progress toward meeting the nationalvisibility goal.  PSCo estimates that theremaining cost for implementation of BART emission control projects isapproximately $141 million in capital costs, which are included in the capitalbudget.

 

PSCoexpects the cost of any required capital investment will be recoverable fromcustomers.  Emissions controls areexpected to be installed between 2012 and 2015. Colorado’s BART state implementation plan has been submitted to the EPAfor approval.  In January 2009, theColorado Air Pollution Control Division (CAPCD) initiated a joint stakeholderprocess to evaluate what types of additional NOx controls may be necessary tomeet reasonable progress goals for Colorado’s Class I areas, the new ozonestandard, and Rocky Mountain National Park nitrogen deposition reductiongoals.  The CAPCD has indicated that itexpects to have a final plan for additional point-source NOx controls by theend of 2010.

 

***CAMR***— In March 2005,the EPA issued the CAMR, which regulated mercury emissions from powerplants.  In February 2008, the U. S.Court of Appeals for the District of Columbia vacated CAMR, which impactsfederal CAMR requirements, but not necessarily state-only mercury legislationand rules.  The EPA has agreed to finalize MACT emissionstandards for all hazardous air pollutants from electric utility steamgenerating units by November 2011 to replace CAMR.  Xcel Energy, the parent company of PSCo,anticipates that the EPA will require affected facilities to demonstratecompliance within 18 to 36 months thereafter.

 

***Colorado Mercury Regulation******—***In Colorado, AQCC passed amercury rule, which requires mercury emission controls capable of achieving80 percent capture to be installed at the Pawnee Generating Station by2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is$2.3 million for capital costs with an annual estimate of$1.4 million for absorbent expense. PSCo is evaluating the emission controls required to meet the state rule forthe remaining units and is currently unable to provide a total capital costestimate.

 

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***Federal CleanWater Act —***The federal Clean Water Act requires the EPAto regulate cooling water intake structures to assure that these structuresreflect the best technology available (BTA) for minimizing adverseenvironmental impacts.  In July 2004,the EPA published phase II of the rule, which applies to existing coolingwater intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Courtof Appeals for the Second Circuit (Court of Appeals) challenging the phase IIrulemaking.  In January 2007, theCourt of Appeals issued its decision and remanded the rule to the EPA forreconsideration.  In June 2007, theEPA suspended the deadlines and referred any implementation to each state’sbest professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U. S. Supreme Courtgranted limited review of the Second Circuit’s opinion to determine whether theEPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U. S. SupremeCourt issued a decision in *Entergy Corp. v.Riverkeeper, Inc.*, concluding that the EPA can consider a costbenefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals, earlieropinion, and gives the EPA the discretion to consider costs and benefits whenit reconsiders its phase II rules.  Untilthe EPA fully responds to the Court of Appeals’ decision, the rule’s compliancerequirements and associated deadlines will remain unknown.  As such, it is not possible to provide anaccurate estimate of the overall cost of this rulemaking at this time.

 

***Notice of Violation (NOV)*** — In July 2002,PSCo received an NOV from the EPA alleging violations of the New Source Review(NSR) requirements of the CAA at the Comanche Station and Pawnee Station inColorado.  The NOV specifically allegesthat various maintenance, repair and replacement projects undertaken at theplants in the mid- to late-1990s should have required a permit under the NSRprocess.  PSCo believes it has acted infull compliance with the CAA and NSR process. PSCo believes that the projects identified in the NOV fit within theroutine maintenance, repair and replacement exemption contained within the NSRregulations or are otherwise not subject to the NSR requirements.  PSCo disagrees with the assertions containedin the NOV and intends to vigorously defend its position.

 

**Asset Retirement 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 *ASC 410Asset Retirement and Environmental Obligations*.  Thisliability will be increased over time by applying the interest method ofaccretion to the liability and the capitalized costs will be depreciated overthe useful life of the related long-lived assets.  The recording of the obligation for regulatedoperations has no income statement impact due to the deferral of theadjustments through the establishment of a regulatory asset.

 

***Recorded ARO —*** AROs have been recorded for steam production,electric transmission and distribution and natural gas distribution.  The steam production obligation includesasbestos, ash-containment facilities and radiation sources.  The asbestos recognition associated with thesteam production includes certain plants at PSCo.  Generally, this asbestos abatement removalobligation originated in 1973 with the Clean Air Act, which applied to thedemolition of buildings or removal of equipment containing asbestos that canbecome airborne on removal.  AROs alsohave been recorded for PSCo steam production related to ash-containmentfacilities such as bottom ash ponds, evaporation ponds and solid wastelandfills. The origination date on the ARO recognition for ash-containmentfacilities at steam plants was the in-service date of various facilities.  Additional AROs have been recorded for steamproduction plant related to radiation sources in equipment used to monitor theflow of coal, lime and other materials through feeders.

 

PSCo recognized an AROfor the retirement costs of its natural gas mains and for the removal ofelectric, transmission and distribution equipment.  The electric transmission and distributionARO consists of many small potential obligations associated with polychlorinatedbiphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries,mercury and street lighting lamps.  Theseelectric and natural gas assets have many in-service dates for which it isdifficult to assign the obligation to a particular year.  Therefore, the obligation was measured usingan average service life.

 

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A reconciliation of thebeginning and ending aggregate carrying amounts of PSCo’s AROs is shown in thetable below for the 12 months ended Dec. 31, 2009 and 2008, respectively:

 
| ** **                              | ** ** | **Beginning**          | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | **Revisions** | ** ** | **Ending**              | ** ** |
|-----------------------------------------|------------|------------------------|------------|-----------------|------------|-----------------|------------|---------------|------------|---------------|------------|-------------------------|------------|
| ** **                              | ** ** | **Balance**            | ** ** | **Liabilities** | ** ** | **Liabilities** | ** ** | ** **    | ** ** | **to  Prior** | ** ** | **Balance**             | ** ** |
| **(Thousands of Dollars)**    | ** ** | **Jan. 1,  2009** | ** ** | **Recognized**  | ** ** | **Settled**     | ** ** | **Accretion** | ** ** | **Estimates** | ** ** | **Dec. 31,  2009** | ** ** |
| **Electric plant**                      | ** ** | ** **             | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | ** **    | ** ** | ** **              | ** ** |
| Steam  production asbestos              |       | $                      | 56,125     |            | $          | —          |       | $             | —     |          | $          | 3,671                   |       | $ | (72 | ) | $ | 59,724 |   |
| Steam  production ash containment       |       | 4,406                  |       | —          |       | —          |       | 261           |       | (80           | )          | 4,587                   |       |
| Steam  production radiation sources     |       | 276                    |       | —          |       | —          |       | 20            |       | (178          | )          | 118                     |       |
| Electric  transmission and distribution |       | 119                    |       | —          |       | —          |       | 7             |       | (11           | )          | 115                     |       |
| **Natural gas plant**                   |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Gas  transmission and distribution      |       | 579                    |       | —          |       | —          |       | 37            |       | —        |       | 616                     |       |
| Total  liability                        |       | $                      | 61,505     |            | $          | —          |       | $             | —     |          | $          | 3,996                   |       | $ | (341 | ) | $ | 65,160 |   |

 

PSCorevised ash-containment facilities, radiation sources and electric transmissionand distribution asset retirement obligations due to new estimates and end oflife dates.

 
| ** **                              | ** ** | **Beginning**          | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | **Revisions** | ** ** | **Ending**              | ** ** |
|-----------------------------------------|------------|------------------------|------------|-----------------|------------|-----------------|------------|---------------|------------|---------------|------------|-------------------------|------------|
| ** **                              | ** ** | **Balance**            | ** ** | **Liabilities** | ** ** | **Liabilities** | ** ** | ** **    | ** ** | **to  Prior** | ** ** | **Balance**             | ** ** |
| **(Thousands of Dollars)**    | ** ** | **Jan. 1,  2008** | ** ** | **Recognized**  | ** ** | **Settled**     | ** ** | **Accretion** | ** ** | **Estimates** | ** ** | **Dec. 31,  2008** | ** ** |
| **Electric plant**                      |       |                   | ** ** | ** **      | ** ** | ** **      | ** ** | ** **    | ** ** | ** **    | ** ** | ** **              | ** ** |
| Steam  production asbestos              |       | $                      | 10,201     |            | $          | 8,231           |       | $             | —     |          | $          | 647                     |       | $ | 37,046 |   | $ | 56,125 |   |
| Steam  production ash containment       |       | 4,058                  |       | —          |       | —          |       | 251           |       | 97            |       | 4,406                   |       |
| Steam  production radiation sources     |       | —                 |       | 274             |       | —          |       | 2             |       | —        |       | 276                     |       |
| Electric  transmission and distribution |       | 82                     |       | —          |       | —          |       | 5             |       | 32            |       | 119                     |       |
| **Natural gas plant**                   |       |                   |       |            |       |            |       |          |       |          |       |                    |       |
| Gas  transmission and distribution      |       | 29,926                 |       | —          |       | —          |       | 741           |       | (30,088       | )          | 579                     |       |
| Total  liability                        |       | $                      | 44,267     |            | $          | 8,505           |       | $             | —     |          | $          | 1,646                   |       | $ | 7,087 |   | $ | 61,505 |   |

 

***IndeterminateAROs******—***PSCo has underground natural gas storagefacilities that have special closure requirements for which the final removaldate cannot be determined, therefore an ARO has not been recorded.

 

***Removal Costs —*** PSCo accrues an obligation for plant removal costsfor generation, transmission and distribution facilities.  Generally, the accrual of future non-AROremoval obligations is not required. However, long-standing ratemaking practices approved by applicable stateand federal regulatory commissions have allowed provisions for such costs inhistorical depreciation rates.  Theseremoval costs have accumulated over a number of years based on varying rates asauthorized by the appropriate regulatory entities.  Given the long periods over which the amountswere accrued and the changing of rates through time, PSCo has estimated theamount of removal costs accumulated through historic depreciation expense basedon current factors used in the existing depreciation rates.  Accordingly, the recorded amounts ofestimated future removal costs are considered regulatory liabilities.  Removal costs as of Dec. 31, 2009 and Dec. 31,2008 were $375 million and $379 million, respectively.

 

**Legal Contingencies**

 

Lawsuits and claims arise in the normalcourse of business. Management, after consultation with legal counsel, hasrecorded an estimate of the probable cost of settlement or other disposition ofthem. The ultimate outcome of these matters cannot presently be determined.Accordingly, the ultimate resolution of these matters could have a materialadverse effect on PSCo’s financial position and results of operations.

 

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**Environmental Litigation**

** **

***Carbon Dioxide EmissionsLawsuit —***In 2004, the attorneys general of eight states andNew York City, as well as several environmental groups, filed lawsuits in U. S.District Court in the Southern District of New York against five utilities,including Xcel Energy, the parent company of PSCo, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co.,Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that 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. On Sept. 19, 2005, the courtgranted the motion to dismiss on constitutional grounds. Plaintiffs filed anappeal to the U. S. Court of Appeals for the Second Circuit.  On Sept. 21, 2009, the Court of Appealsissued an opinion reversing the lower court decision.  On Nov. 5, 2009 the defendants,including Xcel Energy, filed a petition for rehearing and en banc review. It isuncertain when the Court of Appeals will respond to the petition.

 

***Comer vs. Xcel Energy Inc. etal. —***In 2006, Xcel Energy, the parent company of PSCo,received notice of a purported class action lawsuit filed in U. S. DistrictCourt in the Southern District of Mississippi. The lawsuit names more than 45oil, chemical and utility companies, including Xcel Energy, as defendants andalleges that defendants’ CO2 emissions “were a proximate anddirect cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim,several legal theories, including negligence and public and private nuisanceand seek damages related to the loss resulting from the hurricane. Xcel Energybelieves this lawsuit is without merit and intends to vigorously defend itselfagainst these claims. In August 2007, the court dismissed the lawsuit inits entirety against all defendants on constitutional grounds. Plaintiffs fileda notice of appeal to the U. S. Court of Appeals for the Fifth Circuit. On Oct. 16,2009, the U. S. Court of Appeals for the Fifth Circuit reversed the districtcourt decision, in part, concluding that the plaintiffs pleaded sufficientfacts to overcome the constitutional challenges that formed the basis fordismissal by the district court.  On Nov. 27,2009, defendants, including Xcel Energy, filed a petition for en banc review.It is uncertain when the Court of Appeals will respond to the petition.

 

***Native Village of Kivalina vs. XcelEnergy Inc. et al. —***In 2008, the City and NativeVillage of Kivalina, Alaska, filed a lawsuit in U. S. District Court for theNorthern District of California against Xcel Energy, the parent company ofPSCo, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission ofCO2 and other GHGs contribute to global warming,which is harming their village.  XcelEnergy believes the claims asserted in this lawsuit are without merit andjoined with other utility defendants in filing a motion to dismiss on June 30,2008.  On Oct. 15, 2009, the U. S.District Court dismissed the lawsuit on constitutional grounds.  On Nov. 5, 2009, plaintiffs filed anotice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

 

***Comanche Unit 3 CAA Lawsuit*** —****OnJuly 2, 2009, WildEarth Guardians (WEG) filed a lawsuit againstPSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3without a final MACT determination from the Colorado Department of PublicHealth and Environment, Air Pollution Control Division (APCD).  The statehas proposed a more stringent case-by-case MACT determination for Comanche Unit3 that, if final, could increase the operating costs of Comanche Unit 3.  PSCo disputes these claimsand has filed a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emission controlsand pursuant to a valid air permit issued by the APCD.  On Oct. 28, 2009, WEG filed a motion fora preliminary injunction, seeking to enjoin PSCo from constructing, modifying,or operating Comanche Unit 3 prior to receiving a final MACTdetermination.  PSCo strongly opposes theinjunction.  Among other issues, PSCobelieves that WEG has failed to establish a substantial likelihood ofprevailing on the merits of the suit and that therefore there is no valid legalbasis upon which an injunction should be issued.  The court has yet to rule on WEG’smotion and the group sought a temporary restraining order to stop Comanche Unit3 from coming on-line.  The court denied WEG’s request for a temporaryrestraining order on Jan. 26,2010.  On Feb. 23, 2010, the courtheld a hearing on PSCo’s motion to dismiss. It is uncertain when the court will render a decision.

 

**Employment, Tort and Commercial Litigation**

** **

***Qwest vs. Xcel Energy Inc. —***In 2004, anemployee of PSCo was seriously injured when a pole owned by Qwestmalfunctioned.****** In September 2005, the employee commencedan action against Qwest in Colorado state court in Denver.  In April 2006, Qwest filed a third partycomplaint against PSCo based on terms in a joint pole use agreement betweenQwest and PSCo.  In May 2007, thematter was tried and the jury found Qwest solely liable for the accident andthis determination resulted in an award of damages in the amount ofapproximately $90 million.  On April 30,2009, the Colorado Court of Appeals affirmed the jury verdict insofar as itrelates to claims asserted by Qwest against PSCo.  Qwest filed a petition for rehearingwith the Colorado Supreme Court in June 2009. On Feb. 22, 2010 issued a ruling where it will review the Court ofAppeals’ decision as to the punitive damages issue and will not review theCourt of Appeals’ decision as it relates to PSCo.

 

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***Mallon vs. XcelEnergy Inc. —***In August 2007, XcelEnergy, PSCo and PSR Investments, Inc. (PSRI) ( hereafter “ Plaintiffs”)commenced a lawsuit in Colorado state court against Theodore Mallon andTransFinancial Corporation seeking damages for, among other things, breach ofcontract and breach of fiduciary duties associated with the sale of COLIpolicies. In May 2008, Plaintiffs filed an amended complaint that, amongother things, adds Provident Life & Accident Insurance Company(Provident) as a defendant and asserts claims for breach of contract, unjustenrichment and fraudulent concealment against the insurance company. On June 23,2008, Provident filed a motion to dismiss the complaint. On Oct. 22, 2008,the court granted Provident’s motion in part, but denied the motion withrespect to a majority of the core causes of action asserted by Plaintiffs.  In September 2009, Plaintiffs reached asettlement with Mallon and TransFinancial Corporation. Pursuant to the terms ofthe agreement, Mallon agreed to pay Plaintiffs a specified amount and theparties agreed to mutually release each other from all claims.  Plaintiffs continue to prosecute their claimsagainst Provident.  In November 2009,Plaintiffs and Provident filed motions for partial summary judgment, which thecourt subsequently granted in part in favor of Plaintiffs with respect to aninterpretation of the policies.  On Feb. 11, 2010, the court deniedProvident’s motion for partial summary judgment.  Trial for this lawsuit wascontinued to Aug. 16, 2010.

 

***Cabin Creek Hydro Generating StationAccident —***In October 2007, employees of RPICoatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxycoating to the inside of a penstock at PSCo’s Cabin Creek Hydro GeneratingStation near Georgetown, Colo.  A fireoccurred inside a pipe used to deliver water from a reservoir to the hydrofacility.  Five RPI employees were unableto exit the pipe and rescue crews confirmed their deaths.  The accident was investigated by severalstate and federal agencies, including the federal Occupational Safety andHealth Administration (OSHA) and the U. S. Chemical Safety Board and theColorado Bureau of Investigations.

 

InMarch 2008, OSHA proposed penalties totaling $189,900 for twenty-twoserious violations and three willful violations arising out of the accident. InApril 2008, Xcel Energy notified OSHA of its decision to contest all ofthe proposed citations. On May 28, 2008, the Secretary of Labor filed itscomplaint, and Xcel Energy subsequently filed its answer on June 17, 2008.The Court ordered this proceeding stayed until March 3, 2009 andsubsequently extended the stay to October 2009.  The Court is currently considering whether toextend the stay.

 

A lawsuit was filed inColorado state court in Denver on behalf of four of the deceased workers andfour of the injured workers (Foster, et. al. v. PSCo, et. al.). PSCo and XcelEnergy were named as defendants in that case, along with RPI Coatings andrelated companies and the two other contractors who also performed work inconnection with the relining project at Cabin Creek.  A second lawsuit (Ledbetter et. al vs. PSCoet. al) was also filed in Colorado state court in Denver on behalf of threeemployees allegedly injured in the accident. A third lawsuit was filed on behalf of one of the deceased RPI workersin the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, andthe two other contractors as defendants. The court subsequently dismissed the Aguirre lawsuit.  Settlements were subsequently reached in allthree lawsuits.  These confidential settlements are not expected to have amaterial effect on the financial statements of Xcel Energy or its subsidiaries.

 

On Aug. 28, 2009, the U. S. Government announced that Xcel Energyand PSCo have been charged with five misdemeanor counts in federal court inColorado for violation of an OSHA regulation related to the accident atCabin Creek in October 2007.  RPICoatings, the contractor performing the work at the plant, and two individualsemployed by RPI have also been indicted. On Sept. 22, 2009, both Xcel Energyand PSCo entered a not guilty plea, and both will vigorously defend againstthese charges.  In December 2009,Xcel Energy and PSCo filed two separate motions to dismiss.  It is uncertain when the court will rule onthese motions.

 

# ***Stone &Webster, Inc. vs. PSCo —***On July 14, 2009, Stone & Webster, Inc. (Shaw) filed acomplaint against PSCo in State District Court in Denver, Colo. for damagesallegedly arising out of its construction work on the Comanche Unit 3 coalfired plant in Pueblo, Colo.  Shaw, acontractor retained to perform certain engineering, procurement andconstruction work on Comanche Unit 3, alleges, among other things, that PSCowas responsible for and mismanaged the construction of Comanche Unit 3.  Shaw further claims that this allegedmismanagement caused delays and damages in excess of $55 million.  The complaint also alleges that Xcel Energy andrelated entities, including PSCo, guaranteed Shaw $10 million in future profitsunder the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it isentitled.  Accordingly, Shaw seeks anamount up to $10 million relating to the 2003 settlement agreement.  PSCo denies these allegations and believesthe claims are without merit.  PSCo filed an answer and counterclaim in August 2009,denying the allegations in the complaint and alleging that Shaw has failed todischarge its contractual obligations and has caused delays, and that PSCo isentitled, among other things, to liquidated damages and excess costsincurred.  It is not anticipated thatthis lawsuit will affect Comanche Unit 3’s scheduled in-service date.

 

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***Connie DeWeese vs.PSCo***— In November 2008, there was an explosion in Pueblo, Colo. whichdestroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The PuebloFire Department and the Federal Bureau of Alcohol, Tobacco and Firearms(ATF) have determined a natural gas leak from a pipeline under the streetled to the explosion, stating that natural gas passed through the soil andbuilt up in the tavern’s basement.  On Feb. 8,2010 a wrongful death lawsuit was filed in Colorado District Court in Pueblo,Colorado against PSCo and the City of Pueblo by several parties that wereallegedly injured, as a result of this explosion. The plaintiffs are also allegingeconomic and noneconomic damages.   Amongother things, the lawsuit alleges that the accident occurred as a result ofPSCo’s negligence. PSCo denies liability for this accident and intends to filean answer to the complaint on or before March 1, 2010.

 

**16.   Regulatory Assets and Liabilities**

** **

PSCo’s consolidatedfinancial statements are prepared in accordance with the provisions of *ASC 980Regulated Operations*,as discussed in Note 1 to the consolidated financial statements.  Under this guidance, regulatory assets andliabilities can be created for amounts that regulators may allow to becollected, or may require to be paid back to customers in future electric andnatural gas rates.  Any portion of thebusiness that is not rate regulated cannot establish regulatory assets andliabilities.  If changes in the utilityindustry or the business of PSCo no longer allow for the application ofregulatory accounting guidance under GAAP, PSCo would be required to recognizethe write-off of regulatory assets and liabilities in its consolidatedstatement of income.

 

The components ofunamortized regulatory assets and liabilities on the consolidated balancesheets of PSCo are:

 
| ** **                                                                               | ** ** | **See**     | ** ** | **Remaining**             | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------------------------------------------------------------------------------------|------------|-------------|------------|---------------------------|------------|------------|------------|------------|------------|
| **(Thousands of Dollars)**                                                     | ** ** | **Note(s)** | ** ** | **Amortization  Period**  | ** ** | **2009**   | ** ** | **2008**   | ** ** |
| **Regulatory Assets**                                                                    |       |        | ** ** | ** **                |       |       |       |       |       |
| Current  regulatory asset - Recoverable purchased natural gas and electric energy  costs |       | 1           | ** ** | Less than one year        |       | $          | 25,157     |       | $          | 697 |   |
|                                                                                     |       |        |       |                      |       |       |       |       |       |
| Pension  and employee benefit obligations (c)                                            |       | 9           |       | Various                   |       | $          | 560,730    |       | $          | 655,563 |   |
| AFUDC  recorded in plant (a)                                                             |       |        |       | Plant lives               |       | 88,849     |       | 65,382     |       |
| Conservation  programs (a)                                                               |       |        |       | Up to two years           |       | 58,297     |       | 75,543     |       |
| Net  AROs                                                                                |       |        |       | Plant lives               |       | 33,725     |       | 25,983     |       |
| Renewable  and environmental initiative costs                                            |       |        |       | One to six years          |       | 31,165     |       | 10,319     |       |
| Losses  on reacquired debt                                                               |       | 1           |       | Term of related debt      |       | 18,574     |       | 20,486     |       |
| Purchased  power contracts costs                                                         |       | 11          |       | Term of related  contract |       | 13,189     |       | 7,487      |       |
| Environmental  remediation costs                                                         |       | 15          |       | Four to five years        |       | 7,909      |       | 11,542     |       |
| Rate  case costs                                                                         |       | 1           |       | Various                   |       | 2,097      |       | 1,248      |       |
| Contract  valuation adjustments                                                          |       | 11          |       | Term of related  contract |       | —     |       | 60,903     |       |
| Other                                                                                    |       |        |       | Various                   |       | 12,776     |       | 8,556      |       |
| Total  noncurrent regulatory assets                                                      |       |        |       |                      |       | $          | 827,311    |       | $          | 943,012 |   |
|                                                                                     |       |        |       |                      |       |       |       |       |       |
| **Regulatory Liabilities**                                                               |       |        |       |                      |       |       |       |       |       |
| Current  regulatory liability - Deferred electric energy costs                           |       |        |       |                      |       | $          | 64,552     |       | $          | 113,276 |   |
|                                                                                     |       |        |       |                      |       |       |       |       |       |
| Plant  removal costs                                                                     |       |        |       |                      |       | $          | 374,555    |       | $          | 378,863 |   |
| Contract  valuation adjustments (b)                                                      |       |        |       |                      |       | 65,641     |       | 71,675     |       |
| Investment  tax credit deferrals                                                         |       |        |       |                      |       | 30,662     |       | 32,061     |       |
| Deferred  income tax adjustments                                                         |       |        |       |                      |       | 21,771     |       | 23,743     |       |
| Low  income discount program                                                             |       |        |       |                      |       | 4,543      |       | —     |       |
| Gain  on sale of emission allowances                                                     |       |        |       |                      |       | 1,004      |       | 5,093      |       |
| Other                                                                                    |       |        |       |                      |       | 12,315     |       | 3,010      |       |
| Total  noncurrent regulatory liabilities                                                 |       |        |       |                      |       | $          | 510,491    |       | $          | 514,445 |   |

 

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

(b)  Includes the fair value ofcertain long-term purchased power agreements used to meet energy capacityrequirements.

(c)  Includes $11.7 million of unamortized prior servicecosts and $4.2 million of regulatory assets related to the non-qualifiedpension plan.

 

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**17.   Segments and Related Information**

** **

PSCo has two reportablesegments, regulated electric utility and regulated natural gas utility.

 

·                  PSCo’s regulated electric utility segmentgenerates, transmits and distributes electricity in Colorado.  In addition, this segment includes sales forresale and provides wholesale transmission service to various entities in theUnited States.  Regulated electricutility also includes PSCo’s commodity trading operations.

 

·                  PSCo’s regulated natural gas utility segmenttransports, stores and distributes natural gas in portions of Colorado.

 

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

 

Operating results fromthe regulated electric utility and regulated natural gas utility serve as theprimary basis for the chief operating decision maker to evaluate the dualperformance of PSCo.

 

To report net income forregulated electric and regulated natural gas utility segments, PSCo must assignor allocate all costs and certain other income. In general, costs are:

 

·                  Directly assigned wherever applicable;

·                  Allocated based on cost causationallocators wherever applicable; or

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

 

The accounting policiesof the segments are the same as those described in Note 1 to the consolidatedfinancial statements. These segments are managed separately because the revenuestreams are dependent upon regulated rate recovery which is separatelydetermined for each segment.

 
| ** **                                  | ** ** | **Regulated** | ** ** | **Regulated**        | ** ** | **All**   | ** ** | **Reconciling**  | ** ** | **Consolidated** | ** ** |
|---------------------------------------------|------------|---------------|------------|----------------------|------------|-----------|------------|------------------|------------|------------------|------------|
| **(Thousands of Dollars)**        | ** ** | **Electric**  | ** ** | **Natural Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| **2009**                                    |       |          |       |                 |       |      |       |             |       |             |       |
| Operating  revenues from external customers |       | $             | 2,678,578  |                 | $          | 1,093,959 |       | $                | 35,772     |             | $          | — |   | $ | 3,808,309 |   |
| Intersegment  revenues                      |       | 266           |       | 79                   |       | —    |       | (345             | )          | —           |       |
| Total revenues                              |       | $             | 2,678,844  |                 | $          | 1,094,038 |       | $                | 35,772     |             | $          | (345 | ) | $ | 3,808,309 |   |
|                                        |       |          |       |                 |       |      |       |             |       |             |       |
| Depreciation and  amortization              |       | $             | 200,776    |                 | $          | 50,795    |       | $                | 4,491      |             | $          | — |   | $ | 256,062 |   |
| Interest charges  and financing costs       |       | 121,434       |       | 25,242               |       | 1,120     |       | (36              | )          | 147,760          |       |
| Income tax  expense (benefit)               |       | 123,047       |       | 57,375               |       | (10,017   | )          | —           |       | 170,405          |       |
| Net income                                  |       | 242,265       |       | 67,288               |       | 13,767    |       | —           |       | 323,320          |       |
|                                        |       |          |       |                 |       |      |       |             |       |             |       |
| **2008**                                    |       |          |       |                 |       |      |       |             |       |             |       |
| Operating  revenues from external customers |       | $             | 2,982,929  |                 | $          | 1,373,732 |       | $                | 36,383     |             | $          | — |   | $ | 4,393,044 |   |
| Intersegment  revenues                      |       | 229           |       | 100                  |       | —    |       | (329             | )          | —           |       |
| Total revenues                              |       | $             | 2,983,158  |                 | $          | 1,373,832 |       | $                | 36,383     |             | $          | (329 | ) | $ | 4,393,044 |   |
|                                        |       |          |       |                 |       |      |       |             |       |             |       |
| Depreciation and  amortization              |       | $             | 190,544    |                 | $          | 55,638    |       | $                | 6,202      |             | $          | — |   | $ | 252,384 |   |
| Interest charges  and financing costs       |       | 110,263       |       | 25,505               |       | 465       |       | (186             | )          | 136,047          |       |
| Income tax  expense (benefit)               |       | 132,315       |       | 53,075               |       | (18,762   | )          | —           |       | 166,628          |       |
| Net income                                  |       | 230,417       |       | 87,505               |       | 21,874    |       | —           |       | 339,796          |       |

 

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| ** **                                  | ** ** | **Regulated** | ** ** | **Regulated**        | ** ** | **All**   | ** ** | **Reconciling**  | ** ** | **Consolidated** | ** ** |
|---------------------------------------------|------------|---------------|------------|----------------------|------------|-----------|------------|------------------|------------|------------------|------------|
| **(Thousands of Dollars)**        | ** ** | **Electric**  | ** ** | **Natural Gas** | ** ** | **Other** | ** ** | **Eliminations** | ** ** | **Total**        | ** ** |
| **2007**                                    |       |          |       |                 |       |      |       |             |       |             |       |
| Operating  revenues from external customers |       | $             | 2,605,388  |                 | $          | 1,186,106 |       | $                | 36,006     |             | $          | — |   | $ | 3,827,500 |   |
| Intersegment  revenues                      |       | 183           |       | 29                   |       | —    |       | (212             | )          | —           |       |
| Total  revenues                             |       | $             | 2,605,571  |                 | $          | 1,186,135 |       | $                | 36,006     |             | $          | (212 | ) | $ | 3,827,500 |   |
|                                        |       |          |       |                 |       |      |       |             |       |             |       |
| Depreciation  and amortization              |       | $             | 184,367    |                 | $          | 56,313    |       | $                | 6,552      |             | $          | — |   | $ | 247,232 |   |
| Interest  charges and financing costs       |       | 97,208        |       | 24,311               |       | 46,169    |       | (782             | )          | 166,906          |       |
| Income  tax expense (benefit)               |       | 134,671       |       | 35,482               |       | (35,796   | )          | —           |       | 134,357          |       |
| Net  income (loss)                          |       | 241,955       |       | 81,348               |       | (26,409   | )          | —           |       | 296,894          |       |

 

**18.   Related Party Transactions**

 

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

 

Xcel Energy hasestablished a utility money pool arrangement with the utilitysubsidiaries.  See Note 4 for furtherdiscussion of this borrowing arrangement.

 

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

 
| **(Thousands of Dollars)**                | ** ** | **2009**   | ** ** | **2008**   | ** ** | **2007**   | ** ** |
|-----------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Operating  revenues                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Electric                                            |       | $          | 7,751      |       | $          | 38,625     |       | $ | 22,882 |   |
| Other                                               |       | 4,441      |       | 4,459      |       | 4,461      |       |
| Operating  expenses                                 |       |       |       |       |       |       |       |
| Purchased  power                                    |       | 5,976      |       | 7,000      |       | 2,627      |       |
| Other  operations — paid to Xcel Services Inc. |       | 295,934    |       | 285,423    |       | 270,778    |       |
| Interest  expense                                   |       | 586        |       | 1,361      |       | 966        |       |
|                                                     |            |            |            |            |            |            |            |  |  |  |

 

Accounts receivable and payable withaffiliates at Dec. 31, was:

 
| ** **                           | ** ** | **2009**       | ** ** | **2008**     | ** ** |
|--------------------------------------|------------|----------------|------------|--------------|------------|
| ** **                           | ** ** | **Accounts**   | ** ** | **Accounts** | ** ** | **Accounts** | ** ** | **Accounts** | ** ** |
| **(Thousands of Dollars)** | ** ** | **Receivable** | ** ** | **Payable**  | ** ** | **Receivable** | ** ** | **Payable** | ** ** |
| NSP-Minnesota                        |       | $              | 15,789     |         | $          | — |   | $ | 15,987 |   | $ | — |   |
| NSP-Wisconsin                        |       | 30             |       | —       |       | 71 |   | — |   |
| SPS                                  |       | —         |       | 239          |       | — |   | 191 |   |
| Other  subsidiaries of Xcel Energy   |       | 17,577         |       | 40,519       |       | 13,487 |   | 28,715 |   |
|                                 |       | $              | 33,396     |         | $          | 40,758 |   | $ | 29,545 |   | $ | 28,906 |   |

 

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**19. Summarized QuarterlyFinancial Data (Unaudited)**

 

Due to the seasonalityof PSCo’s electric and natural gas sales, such interim results are notnecessarily an appropriate base from which to project annual results.  Summarized quarterly unaudited financial datais as follows:

 
| ** **                  | ** ** | **Quarter  Ended**       | ** ** |
|-----------------------------|------------|--------------------------|------------|
| **(Thousands  of Dollars)** | ** ** | **March 31,  2009** | ** ** | **June 30,  2009** | ** ** | **Sept.  30, 2009** | ** ** | **Dec. 31,  2009** | ** ** |
| Operating  revenues         |       | $                        | 1,002,478  |   | $ | 769,093 |   | $ | 887,960 |   | $ | 1,148,778 |   |
| Operating  income           |       | 141,983                  |       | 116,150 |   | 169,832 |   | 167,706 |   |
| Net  income                 |       | 78,288                   |       | 60,547 |   | 91,224 |   | 93,261 |   |
|                             |            |                          |            |  |  |  |  |  |  |  |  |  |  |

 
| ** **                  | ** ** | **Quarter  Ended**       | ** ** |
|-----------------------------|------------|--------------------------|------------|
| **(Thousands  of Dollars)** | ** ** | **March 31,  2008** | ** ** | **June 30,  2008** | ** ** | **Sept.  30, 2008** | ** ** | **Dec. 31,  2008** | ** ** |
| Operating  revenues         |       | $                        | 1,228,478  |   | $ | 995,307 |   | $ | 1,085,727 |   | $ | 1,083,532 |   |
| Operating  income           |       | 164,847                  |       | 118,096 |   | 154,508 |   | 152,114 |   |
| Net  income                 |       | 94,304                   |       | 66,339 |   | 86,281 |   | 92,872 |   |
|                             |            |                          |            |  |  |  |  |  |  |  |  |  |  |

 

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

** **

During 2008 and 2009, andthrough the date of this report, there were no disagreements with theindependent public accountants for PSCo on accounting principles or practices,financial statement disclosures or audit scope or procedures.

 

**Item 9A — Controls andProcedures**

** **

**Disclosure Controls andProcedures**

** **

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 SEC rules and forms.  In addition, the disclosure controls andprocedures ensure that information required to be disclosed is accumulated andcommunicated to management, including the chief executive officer (CEO) andchief financial officer (CFO), allowing timely decisions regarding requireddisclosure.  As of Dec. 31, 2009,based on an evaluation carried out under the supervision and with theparticipation of PSCo’s management, including the CEO and CFO, of theeffectiveness of its disclosure controls and the procedures, the CEO and CFOhave concluded that PSCo’s disclosure controls and procedures were effective.

 

**InternalControls Over Financial Reporting**

 

No change in PSCo’sinternal control over financial reporting has occurred during the most recentfiscal quarter that has materially affected, or is reasonably likely tomaterially affect, PSCo’s internal control over financial reporting.  PSCo maintains internal control overfinancial reporting to provide reasonable assurance regarding the reliabilityof the financial reporting.  PSCo hasevaluated and documented its controls in process activities, in generalcomputer activities, and on an entity-wide level.  During the year and in preparation forissuing its report for the year ended Dec. 31, 2009 on internal controlsunder section 404 of the Sarbanes-Oxley Act of 2002, PSCo conductedtesting and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing andremediation performed, PSCo did not identify any material control weaknesses,as defined under the standards and rules issued by the Public CompanyAccounting Oversight Board (PCAOB) and as approved by the SEC and as indicatedin Management Report on Internal Controls herein.

 

**Item 9B —Other Information**

 

None.

 

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**PART III**

 

Items 10, 11, 12 and 13of Part III of Form 10-K have been omitted from this report for PSCoin accordance 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 and Corporate Governance**

 

**Item 11 —Executive Compensation**

 

**Item 12 —Security Ownership of Certain Beneficial Owners and Management and Related StockholderMatters**

 

**Item 13 —Certain Relationships and Related Transactions, and Director Independence**

 

**Item 14 —Principal Accountant Fees 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 2010 Annual Meeting ofShareholders, which is incorporated by reference.

 

**PART IV**

 

**Item 15**— **Exhibitsand Financial Statement Schedules**

 

1.               Consolidated Financial Statements:

 

Management Report on Internal Controls **—**For the year ended Dec. 31, 2009.

Report of Independent Registered Public AccountingFirm **—**For the years ended Dec. 31,2009, 2008 and 2007.

Consolidated Statementsof Income **—**For the three yearsended Dec. 31, 2009, 2008 and 2007.

Consolidated Statements of Cash Flows **—** For the three years ended Dec. 31,2009, 2008 and 2007.

Consolidated Balance Sheets **—**As of Dec. 31, 2009 and 2008.

 

2.               Schedule II **—**Valuationand Qualifying Accounts and Reserves for the years ended Dec. 31, 2009,2008 and 2007.

 

3.               Exhibits

 

----

|   |   | *Indicates  incorporation by reference                                                                                                                                 |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   | +Executive Compensation  Arrangements and Benefit Plans Covering Executive Officers and Directors                                                                      |
|   |   |                                                                                                                                                                   |
| 3.01*  |   | Amended and Restated  Articles of Incorporation dated July 15, 1998 (Form 10-K,  Dec. 31, 1998, Exhibit 3(a)(1)).                                  |
| 3.02*  |   | By-laws dated  Nov. 20, 1997 (Form 10-K, Dec. 31, 1997,  Exhibit 3(b)(1)).                                                                         |
| 4.01*  |   | Indenture, dated as of  Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds  (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)). |
| 4.02*  |   | Indentures supplemental  to Indenture dated as of Oct. 1, 1993:                                                                                                   |

 
| **Dated as of** | ** ** | **Previous Filing:  Form; Date or  file no.** | ** ** | **Exhibit  No.** | ** ** |
|---------------------------|------------|-------------------------------------------------------------------|------------|------------------|------------|
| ** **                | ** ** | ** **                                                        | ** ** | ** **       | ** ** |
| Nov. 1, 1993         |       | S-3, (33-51167)                                                   |       | 4(b)(2)          |       |
| Jan. 1, 1994         |       | 10-K, 1993                                                        |       | 4(b)(3)          |       |
| Sept. 2, 1994             |       | 8-K, September 1994                                          |       | 4(b)             |       |
| May 1, 1996          |       | 10-Q, June 30, 1996                                          |       | 4(b)             |       |
| Nov. 1, 1996         |       | 10-K, 1996 (001-03280)                                            |       | 4(b)(3)          |       |
| Feb. 1, 1997         |       | 10-Q, March 31, 1997 (001-03280)                             |       | 4(a)             |       |
| April 1, 1998        |       | 10-Q, March 31, 1998 (001-03280)                             |       | 4(b)             |       |
| Aug. 15, 2002        |       | 10-Q, Sept. 30, 2002 (001-03280)                                  |       | 4.03             |       |
| Sept. 1, 2002             |       | 8-K, Sept. 18, 2002(001-03280)                                    |       | 4.01             |       |
| Sept. 15, 2002            |       | 10-Q, Sept. 30, 2002(001-03280)                                   |       | 4.04             |       |
| March 1, 2003        |       | S-3, April 14, 2003 (333-104504)                             |       | 4(b)(3)          |       |
| April 1, 2003        |       | 10-Q May 15, 2003 (001-03280)                                |       | 4.02             |       |
| May 1, 2003          |       | S-4, June 11, 2003 (333-106011)                              |       | 4.9              |       |
| Sept. 1, 2003             |       | 8-K, Sept. 2, 2003 (001-03280)                                    |       | 4.02             |       |
| Sept. 15, 2003            |       | Xcel 10-K,  March 15, 2004 (001-03034)                       |       | 4.100            |       |
| Aug. 1, 2005         |       | PSCo 8-K, Aug. 18,  2005 (001-03280)                         |       | 4.02             |       |
| Aug. 1, 2007         |       | PSCo 8-K, Aug. 14,  2007 (001-03280)                         |       | 4.01             |       |

 

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| 4.03*   | Indenture dated  July 1, 1999, between PSCo 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*   | Supplemental Indenture,  dated Aug. 1, 2007, between PSCo and U. S. Bank Trust NA, as successor  Trustee. (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated  Aug. 14, 2007).                                                                                                                                                                                                                      |
| 4.06*   | Supplemental Indenture  dated as of Aug. 1, 2008, between PSCo and U. S. Bank Trust NA, as  successor Trustee, creating $300,000,000 principal amount of 5.80% First  Mortgage Bonds, Series No. 18 due 2018 and $300,000,000 principal  amount of 6.50% First Mortgage Bonds, Series No. 19 due 2038  (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no.  001-03280)). |
| 4.07*   | Supplemental  Indenture dated as of May 1, 2009 between PSCo and U. S. Bank Trust NA,  as successor Trustee, creating $400,000,000 principal amount of 5.125 percent  First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of  Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).                                                                                               |
| 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 Inc.  Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K  of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).                                                                                                                                                                                                                                          |
| 10.03*+ | 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).                                                                                                                                                                                                                                |
| 10.04*+ | New Century Energies  Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc.  Form DEF 14A (file no. 001-12927) filed March 26, 1998).                                                                                                                                                                                                                                                        |
| 10.05*+ | Xcel Energy Senior  Executive Severance Policy (2009 Amendment and Restatement)  (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for  the year ended Dec. 31, 2008)                                                                                                                                                                                                                          |
| 10.06*+ | Stock Equivalent Plan  for Non-Employee Directors of Xcel Energy as amended and restated  Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file  no. 001-03034) for the year ended Dec. 31, 2008.                                                                                                                                                                                               |
| 10.07*+ | Xcel Energy  Nonqualified Deferred Compensation Plan as amended and restated Jan. 1,  2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no.  001-03034) for the year ended Dec. 31, 2008).                                                                                                                                                                                                          |
| 10.08*+ | Xcel Energy Non-employee  Directors’ Deferred Compensation Plan as amended and restated on Jan. 1,  2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no.  001-03034) for the year ended Dec. 31, 2008).                                                                                                                                                                                       |
| 10.09*+ | 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).                                                                                                                                                                                                                                               |
| 10.10*+ | 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).                                                                                                                                                                                                                                        |
| 10.11*+ | 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).                                                                                                                                                                                                                                             |
| 10.12*+ | Xcel Energy Omnibus  Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07  to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).                                                                                                                                                                                                                                         |
| 10.13*+ | Xcel Energy Omnibus  2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy  Statement of Xcel Energy Form (file no. 001-03034) dated April 11,  2005).                                                                                                                                                                                                                                            |
| 10.14*+ | Xcel Energy Executive  Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy  Statement of Xcel Energy Form (file no. 001-03034) dated April 11,  2005).                                                                                                                                                                                                                                  |
| 10.15*+ | Xcel Energy  Supplemental Executive Retirement Plan as amended and restated Jan. 1,  2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no.  001-03034) for the year ended Dec. 31, 2008).                                                                                                                                                                                                           |
| 10.16*+ | First Amendment to the  Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of  Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file  no. 001-03034) for the year ended Dec. 31, 2008).                                                                                                                                                                                        |
| 10.17*+ | First Amendment to the  Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009  (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for  the year ended Dec. 31, 2008).                                                                                                                                                                                                           |
| 10.18*  | Amended and Restated  Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of  Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division,  Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31,  1984 — Exhibit 10I(1)).                                                                                                                       |
| 10.19*  | First Amendment to  Amended and Restated Coal Supply Agreement entered into May 27, 1988 but  made effective Jan. 1, 1988 between PSCo and Amax Coal Co.  (Form 10-K (file no. 001-03280) Dec. 31, 1988 —  Exhibit 10I(2)).                                                                                                                                                    |
| 10.20*  | Proposed Settlement  Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to  Form 8-K (file no. 001-03034) dated Dec. 3, 2004).                                                                                                                                                                                                                                                                        |
| 10.21*  | Settlement Agreement  among PSCo 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).                                                                                                                                                                                                                           |

 

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| 10.22*  | Amendment  dated as of April 13, 2009 to the PSCo Credit Agreement dated as of  Dec. 14, 2006 (Exhibit 10.03 to Form 10-Q of Xcel Energy (file  no. 001-03034) for the quarter ended June. 30, 2009).                        |
|---------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.23*  | Credit  Agreement dated Dec. 14, 2006 between PSCo and various lenders  (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034)  for the quarter ended Sept. 30, 2009).                                                   |
| 10.24*+ | Second  Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the  Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to  Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended  Sept. 30, 2009). |
| 10.25*+ | Amendment  dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and  Change-in-Control Policy. Exhibit 10.06 to Form 10-Q of Xcel Energy  (file no. 001-03034) for the quarter ended Sept. 30, 2009).                |
| 10.26*+ | Second  Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan  (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel  Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).                 |
| 10.27*+ | Xcel  Energy Executive Annual Incentive Award Plan Form of Restricted Stock  Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file  no. 001-03034) for the quarter ended Sept. 30, 2009).                                    |
| 10.28*+ | Xcel  Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to  Form 10-K of Xcel Energy (file no. 001-03034) for the year ended  Dec. 31, 2009).                                                                       |
| 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.                                                                                                                                                                                   |

 

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**SCHEDULE II**

 

**PUBLICSERVICE CO. OF COLORADO AND SUBSIDIARIES**

**VALUATIONAND QUALIFYING ACCOUNTS**

**YearsEnded Dec. 31, 2009, 2008 and 2007**

*(amountsin thousands of dollars)*

 
| ** **                                | ** ** | ** **                   | ** ** | **Additions**                        | ** ** | ** **                             | ** ** | ** **                           | ** ** |
|-------------------------------------------|------------|------------------------------|------------|--------------------------------------|------------|----------------------------------------|------------|--------------------------------------|------------|
| ** **                                | ** ** | **Balance  at  Jan. 1** | ** ** | **Charged  to  costs and  expenses** | ** ** | **Charged  to  other accounts****(a)** | ** ** | **Deductions  from reserves****(b)** | ** ** | **Balance  at  Dec. 31** | ** ** |
| **Reserve deducted from related assets:** | ** ** | ** **                   | ** ** | ** **                           | ** ** | ** **                             | ** ** | ** **                           | ** ** | ** ** | ** ** |
| Allowance  for bad debts:                 | ** ** | ** **                   | ** ** | ** **                           | ** ** | ** **                             | ** ** | ** **                           | ** ** | ** ** | ** ** |
| 2009                                      |       | $                            | 29,195     |                                 | $          | 21,189                                 |       | $                                    | 14,364     |   | $ | 40,599 |   | $ | 24,149 |   |
| 2008                                      |       | 23,301                       |       | 28,372                               |       | 8,146                                  |       | 30,624                               |       | 29,195 |   |
| 2007                                      |       | 18,415                       |       | 26,149                               |       | 9,582                                  |       | 30,845                               |       | 23,301 |   |
|                                           |            |                              |            |                                      |            |                                        |            |                                      |            |  |  |  |  |  |  |  |

 

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(a)  Recovery of amountspreviously written off.

(b)  Principally bad debtswritten off or transferred.

 

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**SIGNATURES**

 

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

 
| ** ** | **PUBLIC SERVICE COMPANY OF  COLORADO**     |
|------------|---------------------------------------------|
| ** ** | ** **                                  |
|       | /s/ DAVID M. SPARBY                         |
|       | David M. Sparby                             |
|       | Vice President and  Chief Financial Officer |
|       | (Principal Financial Officer)               |

 

March 1, 2010

 

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

 
| /s/  DAVID L. EVES                               |   | /s/ RICHARD C. KELLY                        |
|--------------------------------------------------|--------|---------------------------------------------|
| David L. Eves                                    |   | Richard C. Kelly                            |
| President, Chief  Executive Officer and Director |   | Chairman and Director                       |
| (Principal  Executive Officer)                   |   |                                        |
|                                             |   |                                        |
| /s/  TERESA S. MADDEN                            |   | /s/ DAVID M. SPARBY                         |
| Teresa  S. Madden                                |   | David M. Sparby                             |
| Vice  President and Controller                   |   | Vice President and  Chief Financial Officer |
| (Principal  Accounting Officer)                  |   | (Principal Financial  Officer)              |
|                                             |   |                                        |
| /s/ BENJAMIN G.S. FOWKE  III                     |   |                                        |
| Benjamin  G.S. Fowke III                         |   |                                        |
| Vice  President and Director                     |   |                                        |

 

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

 

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

 

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