Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

x                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

Or

o                   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-03280

PUBLIC SERVICE COMPANY OF COLORADO

(Exact name of registrant as specified in its charter)

1225 17th Street, Denver, Colorado 80202

(Address of principal executive offices)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  o Yes o No

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes 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.’s Definitive Proxy Statement for its 2010 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Public Service Company 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 reduced disclosure format permitted by General Instruction I(2).

Table of Contents

INDEX

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

2

Table of Contents

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

3

Table of Contents

4

Table of Contents

5

Table of Contents

COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado.  PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 20 percent of its total sales in 2009.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2009.  Generally, PSCo’s earnings range from approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

PSCo owns the following direct subsidiaries:  1480 Welton, Inc., and United Water Company, both of which own certain real estate interests for PSCo; and Green and Clear Lakes Company, which owns water rights.  PSCo also owns PSRI, which held certain former employees’ life insurance policies.  Following settlement with the IRS during 2007, such policies were terminated.  PSCo also holds a controlling interest in several other relatively small ditch and water companies.

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

PSCo focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers.  PSCo files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investment and recover costs of operations.

ELECTRIC UTILITY OPERATIONS

Overview

Climate Change and Clean Energy — Like most other utilities, PSCo is subject to a significant array of environmental regulations.  Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.  PSCo is subject to state RPS requirements which we believe they will be in a position to achieve by the applicable state deadlines.  Although the exact form and design of any federal RPS policy is uncertain at this time, we believe that we will be well-positioned to meet a federal standard as well, although the ultimate design of any federal policy could have a varied impact on PSCo depending upon the energy efficiency and other standards imposed.  In addition, PSCo’s electric generating facilities have been and are likely to be further subject to climate change legislation introduced at either the state or federal level within the next few years.  In 2009, the EPA took a number of steps toward the regulation of GHGs under the CAA.  By spring 2010, the EPA expects to promulgate regulations to control GHGs from mobile sources.  Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.

While PSCo is not currently subject to state or federal limits on its GHG emissions, PSCo has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions.  These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects.  Although the impact of climate change policy on PSCo will depend on the specifics of state and federal policies, legislation and regulation, PSCo believes that, based on prior state commission practice, PSCo would be granted the authority to recover the cost of these initiatives through rates.

Utility Restructuring and Retail Competition — The FERC has continued with its efforts to promote more competitive wholesale markets through open-access transmission and other means.  As a consequence, PSCo and its wholesale customers can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries to serve their native load.  PSCo supports the continued development of wholesale competition and non-discriminatory wholesale open access transmission services.  The FERC has approved the open access transmission planning processes for the PSCo.  PSCo is pursuing upgrades to its transmission system and the systems of neighboring utilities in order to facilitate renewable energy expansion, in response to statutory changes enacted in 2007.

6

Table of Contents

The retail electric business faces competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity.  In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  While PSCo faces these challenges, its rates are competitive with currently available alternatives.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce and certain natural gas transaction in interstate commerce.  PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices; however, PSCo withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

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

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

·                     PCCA — The PCCA allows for recovery of purchased capacity payments for most power purchase agreements.  New rates went into effect Jan. 1, 2010.

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

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

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

·                     RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2 percent of the customer’s total bill.

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

·                     Transmission Cost Adjustment (TCA) — Effective January 2008, the TCA provides for the recovery outside of rate cases of transmission plant revenue requirements and allows for a return on construction work in progress for transmission investments.

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

7

Table of Contents

Performance-Based Regulation Plan (PBRP) and Quality of Service Requirements — PSCo currently operates under an electric and natural gas PBRP.  The major components of this regulatory plan include:

·                     An electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2010; and

·                     A natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2010.

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

Capacity and Demand

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

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

Energy Sources and Related Transmission Initiatives

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

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

Purchased Power — PSCo has contracts to purchase power from other utilities and independent power producers.  Capacity is the measure of the rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricity produced from a particular generating source over a period of time.  Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased.

PSCo also makes short-term purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.

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

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

·                     Add up to 250 MW of concentrating solar thermal technology with thermal storage;

·                     Increase customer efficiency and conservation programs with plans to meet the CPUC goals of annual energy sales reductions to approximately 3,669 GWH, that would yield a demand savings in the range of 886 MW to 994 MW by 2020;

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

·                     Reduce PSCo’s CO2 emissions by 10 and 15 percent below 2005 levels and for PSCo to propose additional reductions to achieve a 20 percent reduction by 2020 in its next plan.

8

Table of Contents

PSCo acquired 174 MW of wind resources and 19 MW of central station photovoltaic (PV) solar resources through separate RFPs and those contracts were specifically 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, and PSCo filed its bid evaluation report with the CPUC in August 2009.

In October 2009, the CPUC approved the acquisitions of the resources identified in the evaluation report.  With minor modification, the CPUC adopted PSCo’s preferred plan which includes an incremental 900 MW of additional intermittent renewable energy resources (wind and PV solar) and approximately 280 MW of “new technology” renewable energy sources.  The CPUC approved the negotiation of purchased power contracts from a pool of PV solar bidders, rather than designating certain bidders.  The CPUC approved the selection of about 800 MW of traditional gas-fired resources.  The CPUC preferred that PSCo file its next resource plan in the normal course of business in the fall of 2011 rather than making an interim filing in 2010.

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

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

·                     15 percent of retail sales for the years 2015 through 2019;

·                     20 percent of retail sales by 2020 and after; and

·                     4 percent must be generated from solar renewable resources with half the solar resources being located at customers’ facilities.

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

The CPUC 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 Transmission Project — PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a certificate of need and public convenience in May 2009.  The project consists of four components of both 230 KV and 345 KV line and substation construction.  The line is intended to assist in bringing solar power in the San Luis Valley to load.  The line is expected to be placed in-service in 2013 if no significant issues in the siting and permitting of the line are encountered.  Several landowners are opposing this transmission line, including two large ranches.  Hearings before an ALJ were conducted in February 2010 with a decision pending.

Fuel Supply and Costs

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

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

9

Table of Contents

Fuel Sources

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

PSCo has contracted for coal suppliers to supply 82 percent of its coal requirements in 2010, 50 percent of its coal requirements in 2011 and 19 percent of its coal requirements in 2012.  Any remaining requirements will be filled through an RFP process or through over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 95 percent of its coal requirements in 2010, 95 percent of its coal requirements in 2011 and 60 percent of its coal requirements in 2012.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather, and availability of equipment.

Natural gas — PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers.  Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel.  The supply contracts expire in various years from 2010 through 2020.  The transportation and storage contracts expire in various years from 2010 to 2040.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2009, PSCo’s commitments related to supply contracts were approximately $159 million and transportation and storage contracts were approximately $1.1 billion.

Wholesale Commodity Marketing Operations

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices, and certain other activities of Xcel Energy’s utility subsidiaries, including enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of PSCo’s utility activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 14 to the consolidated financial statements for a discussion of other regulatory matters.

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

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

Electric Reliability Standards Matters — In 2008, PSCo was subject to an audit of its compliance with the NERC and regional reliability 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 report on PSCo’s compliance with electric reliability standards.  The report found a possible violation of one reliability standard related to relay maintenance.

In 2008, PSCo filed self-reports with the WECC relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection standards.  In 2009, PSCo reached agreement with the WECC that would resolve the open 2008 audit finding and the 2008 self reports by payment of a non-material penalty.  PSCo is in the process of developing a definitive settlement agreement.  This settlement agreement will be subject to NERC and FERC approval.

10

Table of Contents

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.  In 2009, PSCo filed a tariff to participate with other utilities in WestConnect, a consortium of utilities offering regionalized non-firm transmission services.  The WestConnect tariff was effective in the first quarter of 2009.  The WestConnect tariff has not had a material impact on PSCo transmission usage or revenues.  WestConnect may provide wholesale 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 granted market-based rate authority.  Under market based rules, PSCo will be required to file for such reauthorization in June 2010.  Presently the Xcel Energy utility subsidiaries may not sell power at market-based rates within the PSCo balancing authorities, where they have been found to have market power under the FERC’s applicable analysis.  PSCo has cost-based coordination tariffs that it may use to make sales in its balancing authorities.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of use of network transmission service across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies and rules and approved tariffs.  The report represents the preliminary conclusions of the DOI and is subject to additional procedures.  The report does not constitute a finding by the FERC, which may, accept, modify or reject any or all of the preliminary conclusions in the report.  Xcel Energy disagrees with the preliminary report.  Xcel Energy continues to cooperate with the DOI investigation.  Given the preliminary nature of this matter, Xcel Energy is unable to determine if the resolution of this matter will have a material adverse impact on operations, cash flows or financial condition.

Electric Operating Statistics

11

Table of Contents

NATURAL GAS UTILITY OPERATIONS

The most significant recent developments in the natural gas operations of PSCo are continued volatility in natural gas market prices and the continued trend of declining use per residential customer, as well as small commercial and industrial customers (C&I), as a result of improved building construction technologies, higher appliance efficiencies, and conservation.  From 1999 to 2009, average annual sales to the typical PSCo residential customer declined from 96 MMBtu per year to 80 MMBtu per year, and to a typical small C&I customer declined from 463 MMBtu per year to 396 MMBtu per year on a weather-normalized basis.  Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

Public Utility Regulation

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

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

·                     GCA — The GCA mechanism allows PSCo to recover its actual costs of purchased gas and transportation to meet the requirements of its customers.  The GCA is revised quarterly to allow for changes in gas rates.

·                     DSMCA — PSCo has a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.

Performance-Based Regulation and Quality of Service Requirements — The CPUC established a combined electric and natural gas QSP.  See further discussion under Item 1— Electric Utility Operations.

For a further discussion of rate and regulatory matters see Note 14 to the consolidated financial statements.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,897,604 MMBtu.  In addition, firm transportation customers hold 574,910 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,472,514 MMBtu per day.  The maximum daily deliveries for PSCo in 2009 for firm and interruptible services were 1,873,412 MMBtu on Dec. 8, 2009.

PSCo purchases natural gas from independent suppliers.  These purchases are generally priced based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of approximately 1,829,862 MMBtu per day, which includes 834,277 MMBtu of supplies held under third-party underground storage agreements.  During 2009, a capacity release contract of 30,000 MMBtu per day of firm pipeline capacity expired, and another 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 storage capacity was converted to firm transportation with balancing service attached.  In addition, PSCo operates three company-owned underground storage facilities, which provide about 41,000 MMBtu of natural gas supplies on a peak day.  The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations and a small amount is received directly from wellhead sources.

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

12

Table of Contents

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates.  In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC.  This diversification involves numerous supply sources with varied contract lengths.

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

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

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts.  During 2009, PSCo purchased natural gas from approximately 38 suppliers.

Natural Gas Operating Statistics

13

Table of Contents

ENVIRONMENTAL MATTERS

PSCo’s facilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.  Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  PSCo facilities have been designed and constructed to operate in compliance with applicable environmental standards.

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

EMPLOYEES

The number of full-time PSCo employees at Dec. 31, 2009 and 2008 was 2,791 and 2,772, respectively.  Of these full-time employees, 2,124, or 76 percent, and 2,159,or 78 percent, respectively, are covered under collective bargaining agreements.  See Note 9 to the consolidated financial statements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to PSCo and are not considered in the above amounts.

Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes PSCo, is to understand and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable.  Our risk management process has three parts: identification and analysis, management and mitigation, and communication and disclosure. 

Our management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability.  Management broadly considers our business, the utility industry, the domestic and global economy, and the environment to identify risks.  Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process, and internal auditing and compliance with financial and operational controls.  Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy.  At the same time, the business planning process identifies areas where a business area may take inappropriate risk to meet goals.

The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy’s and PSCo’s strategy.  The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management.  At a threshold level, we have developed a robust compliance program and promote a culture of compliance, which mitigates risk.  In addition to the code of conduct, we have a robust compliance program, including policies, training and reporting options. 

Building on the culture of compliance, we manage and mitigate risks through formal structures and groups, including management councils, risk committees, and the services of corporate areas such as internal audit, the corporate controller and legal services.  While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services.  Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and PSCo’s senior management.

14

Table of Contents

Management provides information to the Xcel Energy’s Board in presentations and communications over the course of the Board calendar.  Senior management presents an assessment of key risks to the Board annually.  The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability.  Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and PSCo’s strategy. 

The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees.  The standing committees also oversee risk management as part of their charters.  Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk.  The Xcel Energy Board has overall responsibility for risk oversight.  As described above, the Board reviews the key risk assessment process presented by senior management.  This key risk assessment analyzes the most likely areas of future risk to Xcel Energy.  The Xcel Energy Board also reviews the performance and annual goals of each business area.  This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy.

Risks Associated with Our Business

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

We are subject to comprehensive regulation by federal and state utility regulatory agencies.  The state utility commission regulates many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers.  The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.  Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.  If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.

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

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts.  An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

If interest rates increase, we may incur increased interest expense on variable interest rate debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

15

Table of Contents

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 debt markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous events throughout the world economy.  Capital market disruption events, such as the collapse in the U. S. sub-prime mortgage market and subsequent broad financial market stress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily.  Additional margin requirements could impact our liquidity.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties.  We may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.

We do have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts.  If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long term purchased power contracts, the supplier would need to replace that security with an acceptable substitute.  If the security were not replaced, the party would be in technical default under the contract, which would enable us to exercise our contractual rights.

We are subject to commodity risks and other risks associated with energy markets and energy production.

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

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

16

Table of Contents

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

We are subject to environmental 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 solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental 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 are alleged to be a potentially responsible party that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking 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 also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk.  Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events.  We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.  Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.  Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur.  We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost 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 regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods.  To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

17

Table of Contents

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk.  Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs.  Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress.  Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA.  On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare and that motor vehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010.  Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.  Xcel Energy, our parent company, is also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 15 Commitments and Contingent Liabilities, in our notes to the consolidated financial statements.  While Xcel Energy believes such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages.  Defense costs associated with such litigation can also be significant.  Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals, such as ACES, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap.  Under the proposals, the cap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year.  The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations.  Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions.  There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted.  The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices.  While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not recover all costs related to complying with regulatory requirements imposed on us.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

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

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged recession may include a lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, and may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.  It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur.  See credit risk section for more related information.

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

18

Table of Contents

Our utility operations are subject to long-term planning risks.

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

Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business.  While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.

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

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business.  Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused 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 or decrease in wind generation, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

The term business continuity refers to the ability of an entity to maintain day-to-day operations in response to unforeseen events.  While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations.  The company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on going business operations.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results.  It’s difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information.  We are unable to quantify the potential impact of such an event.

Rising energy prices could negatively impact our business.

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

19

Table of Contents

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

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

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

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

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

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC’s civil penalty authority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of $1 million per violation per day.  In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations.  If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements and related contributions may change in the future.

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

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

20

Table of Contents

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

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets.  This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek 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 billion of short-term debt and current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.

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

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

All of the members of our board of directors, as well as many of our executive officers, are officers of Xcel Energy.  Our board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy.  In 2009, 2008 and 2007 we paid $266.2 million, $271.0 million and $263.9 million of dividends to Xcel Energy, respectively.  If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved Staff Comments

None.

21

Table of Contents

Item 2 — Properties

Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

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

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

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

(d)            Amount represents nameplate rating capacity.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:

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

Natural gas utility mains at Dec. 31, 2009:

Item 3 — Legal Proceedings

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

22

Table of Contents

Additional Information

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

Item 4 — Reserved

PART II

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

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

PSCo had dividend restrictions imposed by its credit facility and FERC rules.

·                 PSCo’s credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent.  PSCo was in compliance as its equity-to-total capitalization ratio was 56 percent and 58 percent at Dec. 31, 2009 and 2008, respectively.

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

The dividends declared during 2009 and 2008 were as follows:

Item 6 — Selected Financial Data

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

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of PSCo during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the respective accompanying consolidated financial statements and notes to the consolidated financial statements.

23

Table of Contents

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,”  “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of PSCo to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and 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 reports filed with the SEC, including “Risk Factors” in Item 1A of  PSCo’s Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to PSCo’s Form 10-K for the year ended Dec. 31, 2009.

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

Results of Operations

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

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energy cost-recovery mechanisms for customers, fluctuations in these costs do not materially affect electric margin.

Electric — The following tables detail the electric revenues and margin:

The following summarizes the components of the changes in electric revenues and margin for the year ended Dec. 31:

Electric Revenues

24

Table of Contents

Electric Margin

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  PSCo has a GCA mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of natural gas purchased for resale and adjusts revenues to reflect such changes in costs upon request by PSCo.  Therefore, fluctuations in the cost of natural gas have little effect on natural gas margin.

Natural Gas — The following table details the natural gas revenues and margin:

The following summarizes the components of the changes in natural gas revenues and margin for the year ended Dec. 31:

Natural Gas Revenues

Natural Gas Margin

25

Table of Contents

Non-Fuel Operating Expenses and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses increased by approximately $24.0 million, or 4.0 percent for 2009, compared to 2008.  The following summarizes the components of the changes in other operating and maintenance expenses for the year ended Dec. 31:

Demand Side Management (DSM) Program Expenses — DSM program expenses increased by approximately $71.9 million for 2009, compared with 2008.  The higher expense is attributable to the expansion of programs and regulatory commitments.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $3.7 million, or 1.5 percent, for 2009 compared with 2008.  The increase is primarily due to planned system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $11.0 million for 2009, compared with 2008.  The increase is primarily due to an adjustment to 2009 accruals based on higher property value mill levy estimates received in 2009.

Other Income, net — Other income, net, decreased by approximately $12.1 million for 2009, compared with 2008.  The decrease is primarily due to lower interest income, deferred compensation and a life insurance refund in 2008.

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

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

Income Taxes — Income tax expense increased by approximately $3.8 million for 2009, compared with 2008.  The effective tax 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 2009 were primarily due to additional state unitary tax expense in 2009.  If state unitary tax expense in 2008 would have been consistent with 2009, the effective tax rate for 2008 would have been 34.4 percent.

The effective tax rates for 2009 and 2008 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant related regulatory differences.  See Note 8 to the consolidated financial statements.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, PSCo is exposed to a variety of market risks.  Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  All financial and commodity related instruments, including derivatives, are subject to market risk.  Market risks associated with derivatives are discussed in further detail in Note 11 to the consolidated financial statements.

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

26

Table of Contents

Commodity Price Risk — PSCo is exposed to commodity price risk in its electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  PSCo’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

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

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

At Dec. 31, 2009, the fair values by source for the commodity trading net asset balances were as follows:

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods.  These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available.  Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms.  The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes.  Market price uncertainty and other risks also are factored into the model.

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

At Dec. 31, 2009, a 10 percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.1 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.1 million.

27

Table of Contents

PSCo’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR).  VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.  The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis, were as follows:

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

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

Credit Risk — PSCo is also exposed to credit risk.  Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their contractual obligations.  PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

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

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

Fair Value Measurements

PSCo adopted new accounting and disclosure guidance on fair value measurements on Jan. 1, 2008 which established a hierarchy for inputs used in measuring fair value, and generally requires that the most observable inputs available be used for fair value measurements.  Note 13 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2009.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues.  Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for this credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2009.

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

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

28

Table of Contents

Item 8 — Financial Statements and Supplementary Data

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

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

29

Table of Contents

Management Report on Internal Controls Over Financial Reporting

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

All internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

PSCo management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2009.  In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2009, the company’s internal control over financial reporting is effective based on those criteria.

PSCo’s independent auditors have issued an audit report on the company’s internal control over financial reporting.  Their report appears herein.

30

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder
Public Service Company of Colorado

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

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting 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 Commission and our report dated March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

31

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Public Service Company of Colorado

We have audited the internal control over financial reporting of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

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

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting 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 Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements 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 an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

32