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

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)

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

1225 17th Street, Denver, Colorado 80202

(Address of principal executive offices)

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.

o Large accelerated filer		oAccelerated filer

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

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).

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

*Xcel Energy Subsidiaries and Affiliates*
NCE		New Century Energies, Inc.
NSP-Minnesota		Northern States Power Company, a Minnesota corporation
NSP-Wisconsin		Northern States Power Company, a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
PSRI		P.S.R. Investments, Inc., a manager of corporate-owned life insurance policies
SPS		Southwestern Public Service Company, a New Mexico corporation
utility subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
WYCO		WYCO Development L.L.C., a joint venture formed between Xcel Energy and Colorado Interstate Gas Company to develop and lease natural gas pipeline, storage, and compression facilities
Xcel Energy		Xcel Energy Inc., a Minnesota corporation
*Federal and State Regulatory Agencies*
CAPCD		Colorado Air Pollution Control Division
CPUC		Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo’s operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U. S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS		Internal Revenue Service
NERC		North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U. S. FERC and government authorities in Canada, to develop and enforce reliability standards.
SEC		Securities and Exchange Commission
*Electric, Purchased Gas and Resource Adjustment Clauses*
AQIR		Air-quality improvement rider. Recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
DSM		Demand side management. Energy conservation and weatherization program for low-income customers.
DSMCA		Demand side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA		Retail electric commodity adjustment. Allows PSCo to recover its actual fuel and purchased energy expense in a calendar year to a benchmark formula. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA.
GCA		Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.

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PCCA	Purchased capacity cost adjustment. Allows PSCo to recover from retail customers for all purchased capacity payments to power suppliers, effective Jan. 1, 2007. Capacity charges are not included in PSCo’s electric rates or other recovery mechanisms.
QSP	Quality of service plan. Provides for bill credits to retail customers if the utility does not achieve certain operational performance targets and/or specific capital investments for reliability. The current QSP for the PSCo electric utility provides for bill credits to customers based on operational performance standards through Dec. 31, 2010. The QSP for the PSCo natural gas utility also expires Dec. 31, 2010.
RES	Renewable energy standard
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
*Other Terms and Abbreviations*
ACES	American Clean Energy and Security Act
AFUDC	Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
ARO	Asset retirement obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC	FASB Accounting Standards Codification
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
CAA	Clean Air Act
CAMR	Clean Air Mercury Rule
CO2	Carbon dioxide
COLI	Corporate-owned life insurance
Codification	FASB Accounting Standards Codification
CWIP	Construction work in progress
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	·	An underlying and a notional amount or payment provision or both,
	·	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
	·	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provide for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
GHG	Greenhouse gas
JOA	Joint operating agreement among the utility subsidiaries
LIBOR	London Interbank Offered Rate
MACT	Maximum Achievable Control Technology
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MISO	Midwest Independent Transmission System Operator
Moody’s	Moody’s Investor Services

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native load		The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas		A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
NOx		Nitrogen oxide
nonutility		All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
O&M		Operating and maintenance
OCI		Other comprehensive income
PBRP		Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PJM		Pennsylvania-New Jersey-Maryland Interconnection
rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
REC		Renewable energy credit
RFP		Request for Proposal
ROE		Return on equity
RPS		Renewable Portfolio Standard, regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SO2		Sulfur dioxide
Standard & Poor’s		Standard & Poor’s Ratings Services
unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission		An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
*Measurements*
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
GWh		Gigawatt hours. One gigawatt hour equals one billion watt hours.
KV		Kilovolts (one KV equals one thousand volts)
KW		Kilowatts (one KW equals one thousand watts)
Kwh		Kilowatt hours
MMBtu		One million BTUs
MW		Megawatts (one MW equals one thousand KW)
Volt		The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt		A measure of power production or usage.

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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.

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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.

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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.

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

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.

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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.

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

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

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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.

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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

	Year Ended Dec. 31,
	2009			2008			2007
Electric sales (millions of Kwh)
Residential	8,715			8,905			8,904
Commercial and industrial	18,448			19,137			18,947
Public authorities and other	226			229			235
Total retail	27,389			28,271			28,086
Sales for resale	6,949			7,756			8,913
Total energy sold	34,338			36,027			36,999

Number of customers at end of period
Residential	1,150,181			1,142,106			1,126,019
Commercial and industrial	151,637			150,826			149,179
Public authorities and other	58,371			58,195			58,559
Total retail	1,360,189			1,351,127			1,333,757
Wholesale	30			35			51
Total customers	1,360,219			1,351,162			1,333,808

Electric revenues (thousands of dollars)
Residential	$	862,242		$	914,531		$	801,162
Commercial and industrial	1,309,770			1,514,652			1,266,800
Public authorities and other	44,434			44,066			41,426
Total retail	2,216,446			2,473,249			2,109,388
Wholesale	349,909			457,623			438,120
Other electric revenues	112,223			52,057			57,880
Total electric revenues	$	2,678,578		$	2,982,929		$	2,605,388

Kwh sales per retail customer	20,136			20,924			21,058
Revenue per retail customer	$	1,630		$	1,831		$	1,582
Residential revenue per Kwh	9.89		¢	10.27		¢	9.00		¢
Commercial and industrial revenue per Kwh	7.10			7.91			6.69
Wholesale revenue per Kwh	5.04			5.90			4.92

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NATURAL GAS UTILITY OPERATIONS

The most 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.

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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:

2009	$	5.13
2008	7.04
2007	5.87

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

	Year Ended Dec. 31,
	2009			2008			2007
Natural gas deliveries (thousands of MMBtu)
Residential	95,566			96,871			93,664
Commercial and industrial	39,878			41,121			40,216
Total retail	135,444			137,992			133,880
Transportation and other	109,906			115,923			117,240
Total deliveries	245,350			253,915			251,120

Number of customers at end of period
Residential	1,193,418			1,186,255			1,169,306
Commercial and industrial	99,654			99,425			98,053
Total retail	1,293,072			1,285,680			1,267,359
Transportation and other	4,789			4,313			4,110
Total customers	1,297,861			1,289,993			1,271,469

Natural gas revenues (thousands of dollars)
Residential	$	745,728		$	941,077		$	808,738
Commercial and industrial	285,199			368,143			313,805
Total retail	1,030,927			1,309,220			1,122,543
Transportation and other	63,032			64,512			63,563
Total natural gas revenues	$	1,093,959		$	1,373,732		$	1,186,106

MMBtu sales per retail customer	104.75			107.33			105.64
Revenue per retail customer	$	797		$	1,018		$	886
Residential revenue per MMBtu	7.80		¢	9.71		¢	8.63		¢
Commercial and industrial revenue per MMBtu	7.15			8.95			7.80
Transportation and other revenue per MMBtu	0.57			0.56			0.54

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ENVIRONMENTAL MATTERS

PSCo’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.

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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.

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We are subject to capital market risk.

Our operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in 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.

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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.

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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.

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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.

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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.

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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:

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

(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.

(d) Amount represents nameplate rating capacity.

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

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

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

Natural gas utility mains at Dec. 31, 2009:

Miles
Transmission		2,301
Distribution		21,242

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.

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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:

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

Item 6 — Selected Financial Data

This is omitted 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.

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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:

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

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

Electric Revenues

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

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Electric Margin

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

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:

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

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

Natural Gas Revenues

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

Natural Gas Margin

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

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Non-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:

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

Demand 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.

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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:

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

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

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

1 — Prices 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.

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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:

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

Interest Rate Risk — PSCo is subject to the risk of fluctuating 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.

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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

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2009			2008			2007
Operating revenues
Electric	$	2,678,578		$	2,982,929		$	2,605,388
Natural gas	1,093,959			1,373,732			1,186,106
Steam and other	35,772			36,383			36,006
Total operating revenues	3,808,309			4,393,044			3,827,500

Operating expenses
Electric fuel and purchased power	1,399,541			1,818,772			1,435,680
Cost of natural gas sold and transported	712,079			994,221			831,826
Cost of sales — steam and other	15,426			15,507			15,646
Other operating and maintenance expenses	628,999			605,008			607,467
Demand-side management program expenses	104,919			32,990			18,010
Depreciation and amortization	256,062			252,384			247,232
Taxes (other than income taxes)	95,612			84,597			85,261
Total operating expenses	3,212,638			3,803,479			3,241,122

Operating income	595,671			589,565			586,378

Other income (expense), net	4,696			16,748			(2,400		)
Allowance for funds used during construction — equity	41,118			36,158			14,179

Interest charges and financing costs
Interest charges — includes other financing costs of $5,686, $5,754, and $5,599, respectively	166,212			154,313			180,230
Allowance for funds used during construction — debt	(18,452		)	(18,266		)	(13,324		)
Total interest charges and financing costs	147,760			136,047			166,906

Income before income taxes	493,725			506,424			431,251
Income taxes	170,405			166,628			134,357
Net income	$	323,320		$	339,796		$	296,894

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

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

	Year Ended Dec. 31
	2009			2008			2007
Operating activities
Net income	$	323,320		$	339,796		$	296,894
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	260,935			260,873			254,840
Demand-side management program expenses	27,625			32,990			18,010
Deferred income taxes	197,348			85,875			79,359
Amortization of investment tax credits	(2,375		)	(2,760		)	(3,869		)
Allowance for equity funds used during construction	(41,118		)	(36,158		)	(14,179		)
Provision for bad debts	21,189			28,372			26,149
Net realized and unrealized hedging and derivative transactions	42,896			(19,012		)	2,583
Changes in operating assets and liabilities:
Accounts receivable	7,082			(10,469		)	(71,005		)
Accrued unbilled revenues	40,573			5,665			(160,830		)
Recoverable purchased natural gas and electric energy costs	(24,460		)	6,535			143,970
Inventories	(19,700		)	(24,028		)	29,673
Prepayments and other	(44,555		)	3,438			(3,198		)
Accounts payable	(32,982		)	(607		)	73,108
Deferred electric energy costs	(50,205		)	78,719			30,132
Net regulatory assets and liabilities	10,414			(10,310		)	26,021
Other current liabilities	(1,531		)	3,700			10,585
Pension and employee benefit obligation	(216,696		)	(63,643		)	(43,811		)
Change in other noncurrent assets	375			436			(15,878		)
Change in other noncurrent liabilities	(24,796		)	15,900			(1,153		)
Net cash provided by operating activities	473,339			695,312			677,401

Investing activities
Utility capital/construction expenditures	(627,421		)	(809,738		)	(806,794		)
Allowance for equity funds used during construction	41,118			36,158			14,179
Investments in utility money pool	(274,200		)	(439,500		)	(721,700		)
Repayments from utility money pool	274,200			540,100			621,100
Other investments	—			23,716			(4,451		)
Net cash used in investing activities	(586,303		)	(649,264		)	(897,666		)

Financing activities
Proceeds from (repayment of) short-term borrowings — net	55,000			(231,007		)	(101,493		)
Proceeds from issuance of long-term debt	394,570			592,389			343,711
Repayment of long-term debt, including reacquisition premiums	(200,000		)	(301,445		)	(101,379		)
Borrowings under utility money pool arrangement	802,800			755,600			486,500
Repayments under utility money pool arrangement	(759,800		)	(714,600		)	(486,500		)
Capital contributions from parent	108,813			127,529			347,924
Dividends paid to parent	(266,188		)	(270,966		)	(263,859		)
Net cash provided by (used in) financing activities	135,195			(42,500		)	224,904

Net increase in cash and cash equivalents	22,231			3,548			4,639
Cash and cash equivalents at beginning of period	11,198			7,650			3,011
Cash and cash equivalents at end of period	$	33,429		$	11,198		$	7,650

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(147,186	)	$	(131,098	)	$	(130,709	)
Cash paid for income taxes, net	(6,155		)	(90,187		)	(61,718		)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	13,332		$	16,379		$	10,902
Storage assets under capital lease	143,105			—			—

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31,
	2009		2008
Assets
Current assets
Cash and cash equivalents	$	33,429	$	11,198
Accounts receivable, net	330,279		362,401
Accounts receivable from affiliates	33,396		29,545
Accrued unbilled revenues	313,953		354,526
Recoverable purchased natural gas and electric energy costs	25,157		697
Inventories	253,648		233,948
Deferred income taxes	81,980		64,181
Derivative instruments valuation	28,704		22,793
Prepayments and other	58,968		14,413
Total current assets	1,159,514		1,093,702

Property, plant and equipment, net	8,104,841		7,592,111

Other assets
Regulatory assets	827,311		943,012
Derivative instruments valuation	104,664		119,534
Other	47,175		46,610
Total other assets	979,150		1,109,156
Total assets	$	10,243,505	$	9,794,969

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	3,964	$	201,510
Short-term debt	95,000		40,000
Borrowings under utility money pool arrangement	84,000		41,000
Accounts payable	422,276		470,158
Accounts payable to affiliates	40,758		28,906
Deferred electric energy costs	64,552		113,276
Taxes accrued	80,303		72,105
Dividends payable to parent	65,822		67,417
Derivative instruments valuation	18,285		28,776
Accrued interest	47,300		50,542
Other	67,692		78,192
Total current liabilities	989,952		1,191,882

Deferred credits and other liabilities
Deferred income taxes	1,447,143		1,204,861
Deferred investment tax credits	50,031		52,406
Regulatory liabilities	510,491		514,445
Pension and employee benefit obligations	257,881		527,264
Customer advances	271,171		290,937
Derivative instruments valuation	49,587		62,126
Asset retirement obligations	65,160		61,505
Other	31,287		22,491
Total deferred credits and other liabilities	2,682,751		2,736,035

Commitments and contingent liabilities
Capitalization
Long-term debt	2,824,988		2,289,251
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—		—
Additional paid-in capital	2,995,470		2,886,657
Retained earnings	742,243		683,516
Accumulated other comprehensive income	8,101		7,628
Total common stockholder’s equity	3,745,814		3,577,801
Total liabilities and equity	$	10,243,505	$	9,794,969

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except share data)

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

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)

	Dec. 31
	2009			2008
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2012, 7.875%	$	600,000		$	600,000
March 1, 2013, 4.875%	250,000			250,000
April 1, 2014, 5.5%	275,000			275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Aug. 1, 2018, 5.8%	300,000			300,000
Jan. 1, 2019, 5.1% (a)	48,750			48,750
June 1, 2019, 5.125%	400,000			—
Sept. 1, 2037, 6.25%	350,000			350,000
Aug. 1, 2038, 6.5%	300,000			300,000
Unsecured Senior A Notes, due July 15, 2009, 6.875%	—			200,000
Capital lease obligations, through 2060, 11.2% — 14.1%	183,026			43,423
Unamortized debt	(7,324		)	(5,912		)
Total	2,828,952			2,490,761
Less current maturities	3,964			201,510
Total long-term debt	$	2,824,988		$	2,289,251

Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2009 and 2008	$	—		$	—
Additional paid-in capital	2,995,470			2,886,657
Retained earnings	742,243			683,516
Accumulated comprehensive income	8,101			7,628
Total common stockholder’s equity	$	3,745,814		$	3,577,801

(a) Pollution control financing

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — PSCo is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. PSCo is subject to regulation by the FERC and the CPUC. All of PSCo’s accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — PSCo has subsidiaries, which have been consolidated and for which all intercompany transactions and balances have been eliminated.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.

PSCo has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and electric fuel costs, as well as purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. A summary of significant rate-adjustment mechanisms follows:

· PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA for the company’s retail jurisdiction. The ECA mechanism was extended in 2009 and went into effect in January 2010. The ECA allows for sharing of margins on short term energy sales.

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

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

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

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with ASC 815 Derivatives and Hedging. In addition, commodity trading results include the impact of all margin-sharing mechanisms. For more information, see Note 11 to the consolidated financial statements.

Fair Value Measurements — PSCo presents cash equivalents, interest rate derivatives, and commodity derivatives at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value and losses are recorded in earnings if fair value falls below recorded cost. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models as primary inputs to determine fair value.

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Types of and Accounting for Derivative Instruments — PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by ASC 815 Derivatives and Hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for the sale of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; hedge transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The accounting for derivatives requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. PSCo formally documents all hedging relationships in accordance with this guidance. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction. In addition, at inception and on a quarterly basis, PSCo formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. PSCo discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case associated deferred amounts are immediately recognized in current earnings.

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

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

For further discussion of PSCo’s risk management and derivative activities see Note 11 to the consolidated financial statements.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Regulatory obligations to incur removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repair and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use.

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

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.

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

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Litigation accruals are recorded when it is probable PSCo is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.

Income Taxes — PSCo accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

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

Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 16 to the consolidated financial statements. For more information on income taxes, see Note 8 to the consolidated financial statements.

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

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

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

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Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually, and revised, if appropriate.

Cash and Cash Equivalents — PSCo considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Inventory — All inventories are recorded at average cost.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with ASC 980 Regulated Operations. Under this guidance:

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

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

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 16 to the consolidated financial statements.

Deferred Financing Costs — Other assets included deferred financing costs, net of amortization, of approximately $17.5 million and $16.4 million at Dec. 31, 2009 and 2008, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of write-offs and an allowance for bad debts. PSCo establishes an allowance for uncollectible receivables based on a reserve policy that reflects its expected exposure to the credit risk of customers.

Renewable Energy Credits — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPSs enacted by those states that are encouraging construction and consumption of renewable energy, but can also be sold separately from the energy produced. Currently, PSCo acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchase as a result of meeting load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are retired for compliance purposes is recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. PSCo follows the inventory accounting model for all allowances. The sales of allowances are reported in the operating activities section of the consolidated statements of cash flows. The net margin on sales of emission allowances is included in electric utility operating revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

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Reclassifications — Demand side management program expenses were reclassified as a separate item from depreciation and amortization within the consolidated statements of cash flows. Pension and employee benefit obligations were reclassified as a separate item from change in other noncurrent liabilities within the consolidated statements of cash flows. The reclassifications did not have an impact on net cash provided by operating activities.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2009 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2. Accounting Pronouncements

Recently Adopted

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

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

Derivatives and Hedging Disclosures — In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 11 to the consolidated financial statements.

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

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

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Other-Than-Temporary Impairments — Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance was effective for interim and annual periods ending after June 15, 2009. PSCo implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Accounting Standards Codification — In June 2009, the FASB issued Topic 105 — Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. PSCo implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on PSCo’s consolidated financial statements.

Postretirement Benefit Plans — In December 2008, the FASB issued new guidance on employers’ disclosures about postretirement benefit plan assets. The guidance amends and expands previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements. This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 9 to the consolidated financial statements.

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

Recently Issued

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009. PSCo does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. PSCo does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

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

4. Short-Term Borrowings

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

Money Pool — Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The Holding Company may make investments in the utility subsidiaries at market-based interest rates. However, the money pool arrangement does not allow the utility subsidiaries to make investments in the Holding Company. PSCo has approval to borrow up to $250 million under the arrangement. At Dec. 31, 2009 and 2008, PSCo had money pool borrowings of $84.0 million and $41.0 million, respectively. The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and 3.48 percent, respectively.

5. Long-Term Debt

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

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

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

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. PSCo has the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval.

· The credit facility has one financial covenant requiring that PSCo’s debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 45 percent and 42 percent at Dec. 31, 2009 and 2008, respectively. If PSCo does not comply with the covenant, it is deemed an event of default and any outstanding amounts due under the facility can be declared due by the lender.

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

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

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

Long-Term Borrowings

In June 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds, series due 2019. PSCo added the proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the net proceeds to fund the payment at maturity of $200 million of 6.875 percent unsecured senior notes due July 15, 2009.

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

Maturities of long-term debt are:

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

6. Preferred Stock

PSCo has authorized the issuance of preferred stock.

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

7. Joint Plant Ownership

Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2009:

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

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PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity, excluding Comanche Unit 3. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs. PSCo began major construction on a new jointly owned 750 MW, coal-fired unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche Unit 3, was still underway in 2009 and in-service is expected by the end of the first quarter of 2010. The plant experienced certain boiler tube leaks in the start-up process that are being resolved. PSCo is the operating agent under the joint ownership agreement.

8. Income Taxes

COLI — In 2007, Xcel Energy and the U.S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. The total exposure for the tax years in dispute through 2007 was approximately $583 million, which includes income tax, interest and potential penalties. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed. We anticipate these proceedings to be dismissed in 2010.

Terms of the Final Settlement

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

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

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

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2008, the IRS completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2004 and 2005 federal income tax returns expired on Dec. 31, 2009. The IRS commenced an examination of tax years 2006 and 2007 in 2008, and this audit is expected to be completed in the first quarter of 2010. As of Dec. 31, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2009, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The amount of unrecognized tax benefits was $7.2 million and $10.3 million on Dec. 31, 2009 and Dec. 31, 2008, respectively. A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

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

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

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

The decrease in the unrecognized tax benefit balance of $3.1 million in 2009 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of similar uncertain tax positions related to ongoing activity. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

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

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2009 or Dec. 31, 2008.

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

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

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

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

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

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

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

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

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

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

(Thousands of Dollars)	2009		2008
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,352,421	$	1,176,313
Employee benefits	98,835		33,819
Regulatory assets	62,876		52,728
Deferred fuel costs	49,557		35,442
Other	11,243		17,024
Total deferred tax liabilities	$	1,574,932	$	1,315,326

Deferred tax assets:
Unbilled revenue - fuel costs	$	59,318	$	78,175
NOL carryforward	67,749		24,420
Tax credit carryforward	20,737		17,931
Deferred investment tax credits	19,011		19,891
Regulatory liabilities	20,371		16,166
Bad debts	9,176		11,082
Deferred rent	4,142		—
Other	9,264		6,981
Total deferred tax assets	$	209,768	$	174,646
Net deferred tax liability	$	1,365,164	$	1,140,680

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9. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.

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

Effective Jan. 1, 2009, Xcel Energy and PSCo adopted new guidance on employers’ disclosures about pension and postretirement benefit plan assets. The new guidance expands employers’ disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities’ recurring fair value measurements prescribed by ASC 820 Fair Value Measurements.

ASC 820 Fair Value Measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels defined by the hierarchy and examples of each level are as follows:

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

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

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as asset and mortgage backed securities, for which subjective risk-based adjustments to estimated yield and forecasted prepayments are significant inputs.

Pension Benefits

Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits. Xcel Energy’s and PSCo’s policy is to fully fund the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws, into an external trust over time.

Xcel Energy and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the portfolio of pension investments is 8.98 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 and 2007 were below the assumed level of 8.75 percent. Xcel Energy and PSCo continually review the pension assumptions. In 2010, Xcel Energy will use an investment-return assumption, for all pension plans in aggregate, of 7.79 percent.

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

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The following table presents the target pension asset allocations for 2009 and 2008:

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

In 2009, Xcel Energy and PSCo engaged J.P. Morgan’s Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension. The investment strategy employed during 2009 is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

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

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

The following table presents the changes in Level 3 pension plan assets for the year ended Dec. 31, 2009:

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

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

(Thousands of Dollars)	2009				2008
Accumulated Benefit Obligation at Dec. 31	$	2,676,174			$	2,435,513

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,598,032			$	2,662,759
Service cost	65,461				62,698
Interest cost	169,790				167,881
Plan amendments	(35,341			)	—
Actuarial loss (gain)	223,122				(47,509			)
Benefit payments	(191,433			)	(247,797			)
Obligation at Dec. 31	$	2,829,631			$	2,598,032

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	2,185,203			$	3,186,273
Actual return (loss) on plan assets	255,556				(788,273			)
Employer contributions	200,000				35,000
Benefit payments	(191,433			)	(247,797			)
Fair value of plan assets at Dec. 31	$	2,449,326			$	2,185,203

Funded Status of Plans at Dec. 31:
Funded status	$	(380,305		)	$	(412,829		)
Noncurrent assets	—				15,612
Noncurrent liabilities	(380,305			)	(428,441			)
Net pension amounts recognized on consolidated balance sheets	$	(380,305		)	$	(412,829		)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	447,815			$	394,045
Prior service (credit) cost	(22,221			)	17,287
Total	$	425,594			$	411,332

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	425,594			$	411,332
Total	$	425,594			$	411,332

PSCo accrued benefit liability recorded	90,989				251,178

Measurement Date	Dec. 31, 2009				Dec. 31, 2008

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.00			%	6.75			%
Expected average long-term increase in compensation level	4.00				4.00
Mortality table	RP		2000		RP		2000

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

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Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2007 through 2009 for the pension plans and are not expected to require cash funding in 2010.

Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009.

· Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009, $35 million in 2008 and $35 million in 2007.

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

· Pension funding contributions for 2011, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million.

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

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

(Thousands of Dollars)	2009			2008			2007
Service cost	$	65,461		$	62,698		$	61,392
Interest cost	169,790			167,881			162,774
Expected return on plan assets	(256,538		)	(274,338		)	(264,831		)
Amortization of prior service cost	24,618			20,584			25,056
Amortization of net loss	12,455			11,156			15,845
Net periodic pension cost (credit)	15,786			(12,019		)	236

PSCo:
Net periodic pension cost	13,847			11,120			18,348

Significant Assumptions Used to Measure Costs:
Discount rate for year-end valuation	6.75		%	6.25		%	6.00		%
Expected average long-term increase in compensation level	4.00			4.00			4.00
Expected average long-term rate of return on assets	8.50			8.75			8.75

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2010 pension cost calculations will be 7.79 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

Xcel Energy, which includes PSCo, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of operating cash flows.

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo were approximately $6.4 million in 2009, $6.1 million in 2008 and $7.9 million in 2007.

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Postretirement Health Care Benefits

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

In 1993, Xcel Energy and PSCo adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs. PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional postretirement benefit costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy and PSCo base the investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

The following table presents, for each of the fair value hierarchy levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2009:

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

The following table presents the changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2009:

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

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

(Thousands of Dollars)	2009				2008
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	794,597			$	830,315
Service cost	4,665				5,350
Interest cost	50,412				51,047
Medicare subsidy reimbursements	3,226				6,178
Amendments	(27,407			)	—
Plan participants’ contributions	13,786				13,892
Actuarial gain	(47,446			)	(46,827			)
Benefit payments	(62,931			)	(65,358			)
Obligation at Dec. 31	$	728,902			$	794,597

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	299,566			$	427,459
Actual return (loss) return on plan assets	72,101				(132,226			)
Plan participants’ contributions	13,786				13,892
Employer contributions	62,167				55,799
Benefit payments	(62,931			)	(65,358			)
Fair value of plan assets at Dec. 31	$	384,689			$	299,566

Funded Status at Dec. 31:
Funded status	$	(344,213		)	$	(495,031		)
Current liabilities	(2,240			)	(4,928			)
Noncurrent liabilities	(341,973			)	(490,103			)
Net amounts recognized on consolidated balance sheets	$	(344,213		)	$	(495,031		)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	110,766			$	181,157
Prior service credit	(25,262			)	(1,757			)
Transition obligation	33,797				44,801
Total	$	119,301			$	224,201

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	119,301				224,201
Total	$	119,301			$	224,201

PSCo accrued benefit liability recorded	148,022				254,003

Measurement Date	Dec. 31, 2009				Dec. 31, 2008

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.00			%	6.75			%
Mortality table	RP		2000		RP		2000

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Effective Dec. 31, 2009, Xcel Energy and PSCo reduced the initial medical trend assumption from 7.4 percent to 6.8 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is three years. Xcel Energy and PSCo base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

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

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

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes PSCo, contributed $62.2 million during 2009 and $55.6 million in 2008 and expects to contribute approximately $45.4 million during 2010.

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

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

(Thousands of Dollars)	2009			2008			2007
Service cost	$	4,665		$	5,350		$	5,813
Interest cost	50,412			51,047			50,475
Expected return on plan assets	(22,775		)	(31,851		)	(30,401		)
Amortization of transition obligation	14,444			14,577			14,577
Amortization of prior service cost	(2,726		)	(2,175		)	(2,178		)
Amortization of net loss	19,329			11,498			14,198
Net periodic postretirement benefit cost	63,349			48,446			52,484
PSCo:
Net periodic postretirement benefit cost recognized	40,277			26,989			28,661
Additional cost recognized due to effects of regulation	3,891			3,891			3,891
Net benefit cost recognized for financial reporting	$	44,168		$	30,880		$	32,552

Significant Assumptions Used to Measure Costs:
Discount rate for year-end valuation	6.75		%	6.25		%	6.00		%
Expected average long-term rate of return on assets (before tax)	7.50			7.50			7.50

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Projected Benefit Payments

The following table lists the projected benefit payments for the pension and postretirement benefit plans.

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2010	$	238,929	$	58,738	$	4,901	$	53,837
2011	230,833		60,202		5,184		55,018
2012	234,256		60,665		5,529		55,136
2013	237,817		60,785		5,841		54,944
2014	244,160		61,260		6,075		55,185
2015-2019	1,256,824		313,040		33,598		279,442

10. Other Income (Expense), Net

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

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

11. Derivative Instruments

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

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. See additional information pertaining to the valuation of derivative instruments in Note 13 to the consolidated financial statements.

Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2009, accumulated other comprehensive income related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.

At Dec. 31, 2009, PSCo had vehicle fuel contracts designated as cash flow hedges extending through December 2012. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2009 and 2008.

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At Dec. 31, 2009, accumulated other comprehensive income related to vehicle fuel cash flow hedges included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income subject to applicable customer margin-sharing mechanisms.

PSCo had no derivative instruments designated as fair value hedges during the year ended Dec. 31, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for the period.

The following table shows the major components of derivative instruments valuation in the consolidated balance sheets:

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

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, PSCo began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following tables:

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

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The following table details the fair value of commodity derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:

	Dec. 31, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative assets
Other derivative instruments:
Trading commodity	$	3,367	$	(2,121	)	$	1,246
Natural gas commodity	8,753		111			8,864
Total current derivative assets	$	12,120	$	(2,010	)	$	10,110

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	69	$	—		$	69
Other derivative instruments:						—
Trading commodity	3,048		677			3,725
Natural gas commodity	476		248			724
	3,524		925			4,449
Total noncurrent derivative assets	$	3,593	$	925		$	4,518

	Dec. 31, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation

Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	1,338	$	—		$	1,338

Other derivative instruments:
Trading commodity	4,391		(2,591		)	1,800
Natural gas commodity	6,089		111			6,200
	10,480		(2,480		)	8,000
Total current derivative liabilities	$	11,818	$	(2,480	)	$	9,338

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	1,373	$	675		$	2,048
Natural gas commodity	302		248			550
Total noncurrent derivative liabilities	$	1,675	$	923		$	2,598

(a) ASC 815, Derivatives and Hedging, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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The following table details the impact of derivative activity during the year ended Dec. 31, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

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

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	2,009	(b)
Natural gas commodity	—			3,880			—			8,190		(c)	—
Total	$	—		$	3,880		$	—		$	8,190		$	2,009

(a) Recorded to other operating and maintenance expenses.

(b) Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross income, as appropriate.

(c) Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d) Recorded to interest charges.

At Dec. 31, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 3,559,000 megawatt (MW) hours of electricity, 45,352,000 MMBtu of natural gas, and 1,559,000 gallons of vehicle fuel. These amounts reflect the gross notional amounts of futures and forwards, and are not reflective of net positions in the underlying commodities. Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Credit Related Contingent Features — Contract provisions of PSCo’s derivative instruments may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit rating. If the credit rating of PSCo at Dec. 31, 2009 were downgraded below investment grade, contracts underlying $0.6 million of derivative instruments in a liability position would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $3.4 million. At Dec. 31, 2009, there was no collateral posted on these specific contracts.

Certain of PSCo’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2009, PSCo had no collateral posted related to adequate assurance clauses in derivative contracts.

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12. Financial Instruments

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

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

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

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

Letters of Credit

PSCo use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2009 and 2008, there were $4.6 million and $4.9 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

13. Fair Value Measurements

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

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as commodity derivative contracts listed on the New York Mercantile Exchange.

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

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the long-term commodity price forecasts used to determine the fair value of long-term energy forwards.

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, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

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

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

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

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

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

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

14. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

PSCo 2009 Electric Rate Case — In November 2008, PSCo filed a request with the CPUC to increase Colorado electric rates by $174.7 million annually, or approximately 7.4 percent. The rate filing was based on a 2009 forecast test year, an electric rate base of $4.2 billion, a requested ROE of 11.0 percent and an equity ratio of 58.08 percent. PSCo’s request included a return of approximately $40 million for CWIP associated with incremental expenditures on the Comanche Unit 3 since Jan. 1, 2007. PSCo does not record AFUDC income for the months this return is actually received from customers.

In March 2009, PSCo filed rebuttal testimony and revised its rate increase request to $159.3 million to reflect updated data. In May 2009, the CPUC approved a blackbox settlement agreement which provided for an overall $112.2 million increase in base rates. The settlement provides that incremental CWIP not included in existing rates for the Comanche Unit 3 be removed from rate base and that PSCo would be allowed to continue to record AFUDC income on this balance until the Comanche Unit 3 is placed into service. New rates went into effect on July 1, 2009.

PSCo 2010 Electric Rate Case — In May 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010. The request was based on a 2010 forecast test year, an 11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05 percent, In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million.

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Renewable Energy Credit (REC) Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. PSCo’s request sought 45 percent of the margins on these specific transactions for both the customers and PSCo with the remaining ten percent being used to fund a program to develop carbon offset projects and expertise. On Jan. 20, 2010, PSCo, the Office of Consumer Council, the CPUC staff, the Colorado governor’s energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that 10 percent of margins will go to carbon offsets, 40 percent of the first $10 million in margins, 35 percent of the next $20 million and 30 percent of all remaining margins will go to PSCo with all remaining margins going to Colorado retail the customers as a credit toward renewable energy projects. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers. It is expected that PSCo will file an application by Aug. 31, 2010 for future treatment of margins from transactions for RECs bundled with energy after the end of the pilot program. On Feb. 18, 2010, the CPUC approved the settlement.

Pending and Recently Concluded Regulatory Proceedings — FERC

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

In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC. The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued. The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC.

Wholesale Rate Case — In 2009, PSCo proposed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million. PSCo has requested that FERC suspend action on the filing to allow time for settlement negotiations. Settlement discussions with PSCo’s wholesale customers are continuing. PSCo expects rates subject to refund to go into effect in the second quarter of 2010.

15. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2009, the estimated cost of the capital expenditure programs and other capital requirements of PSCo is approximately $610 million in 2010, $600 million in 2011 and $710 million in 2012.

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

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Fuel Contracts — PSCo has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2010 and 2040. In addition, PSCo may be required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs to customers.

The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2009, are as follows:

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

Purchased Power Agreements — PSCo has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages and meet operating reserve obligations. PSCo has various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices. However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

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

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

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

In 1999, WYCO was formed as a joint venture between Xcel Energy and Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. In 2009, WYCO’s Totem gas storage facilities were placed in service. WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement that commenced on July 1, 2009.

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

Following is a summary of assets held under capital leases:

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

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

Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with ASC 840 Leases. Future commitments under operating and capital leases are:

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

(a) Amounts not included in purchase power agreement estimated future payments above.

(b) Purchase power agreeement operating leases contractually expire through 2028.

Environmental Contingencies

PSCo has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.

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

Asbestos Removal — Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. PSCo has recorded an estimate for final removal of the asbestos as an ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

EPA GHG Endangerment Finding — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty 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.

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Some PSCo generating facilities will be subject to BART requirements.

States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. In May 2006, the Colorado Air Quality Control Commission (AQCC) promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. PSCo estimates that the remaining cost for implementation of BART emission control projects is approximately $141 million in capital costs, which are included in the capital budget.

PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2015. Colorado’s BART state implementation plan has been submitted to the EPA for approval. In January 2009, the Colorado Air Pollution Control Division (CAPCD) initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado’s Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.

CAMR — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR. Xcel Energy, the parent company of PSCo, anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

Colorado Mercury Regulation — In Colorado, AQCC passed a mercury rule, which requires mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for absorbent expense. PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.

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

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

Asset Retirement Obligations

PSCo records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with ASC 410 Asset Retirement and Environmental Obligations. This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

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

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

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

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

PSCo revised ash-containment facilities, radiation sources and electric transmission and distribution asset retirement obligations due to new estimates and end of life dates.

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

Indeterminate AROs — PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined, therefore an ARO has not been recorded.

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

Legal Contingencies

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

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Environmental Litigation

Carbon Dioxide Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of PSCo, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U. S. Court of Appeals for the Second Circuit. On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision. On Nov. 5, 2009 the defendants, including Xcel Energy, filed a petition for rehearing and en banc review. It is uncertain when the Court of Appeals will respond to the petition.

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

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy, the parent company of PSCo, and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds. On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

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

Employment, Tort and Commercial Litigation

Qwest vs. Xcel Energy Inc. — In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. On April 30, 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009. On Feb. 22, 2010 issued a ruling where it will review the Court of Appeals’ decision as to the punitive damages issue and will not review the Court of Appeals’ decision as it relates to PSCo.

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

Cabin Creek Hydro Generating Station Accident — In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U. S. Chemical Safety Board and the Colorado Bureau of Investigations.

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

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

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

Stone & Webster, Inc. vs. PSCo — On July 14, 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant in Pueblo, Colo. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo was responsible for and mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages in excess of $55 million. The complaint also alleges that Xcel Energy and related entities, including PSCo, guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled, among other things, to liquidated damages and excess costs incurred. It is not anticipated that this lawsuit will affect Comanche Unit 3’s scheduled in-service date.

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

16. Regulatory Assets and Liabilities

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

The components of unamortized regulatory assets and liabilities on the consolidated balance sheets of PSCo are:

	See	Remaining
(Thousands of Dollars)	Note(s)	Amortization Period	2009		2008
Regulatory Assets
Current regulatory asset - Recoverable purchased natural gas and electric energy costs	1	Less than one year	$	25,157	$	697

Pension and employee benefit obligations (c)	9	Various	$	560,730	$	655,563
AFUDC recorded in plant (a)		Plant lives	88,849		65,382
Conservation programs (a)		Up to two years	58,297		75,543
Net AROs		Plant lives	33,725		25,983
Renewable and environmental initiative costs		One to six years	31,165		10,319
Losses on reacquired debt	1	Term of related debt	18,574		20,486
Purchased power contracts costs	11	Term of related contract	13,189		7,487
Environmental remediation costs	15	Four to five years	7,909		11,542
Rate case costs	1	Various	2,097		1,248
Contract valuation adjustments	11	Term of related contract	—		60,903
Other		Various	12,776		8,556
Total noncurrent regulatory assets			$	827,311	$	943,012

Regulatory Liabilities
Current regulatory liability - Deferred electric energy costs			$	64,552	$	113,276

Plant removal costs			$	374,555	$	378,863
Contract valuation adjustments (b)			65,641		71,675
Investment tax credit deferrals			30,662		32,061
Deferred income tax adjustments			21,771		23,743
Low income discount program			4,543		—
Gain on sale of emission allowances			1,004		5,093
Other			12,315		3,010
Total noncurrent regulatory liabilities			$	510,491	$	514,445

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

(b) Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.

(c) Includes $11.7 million of unamortized prior service costs and $4.2 million of regulatory assets related to the non-qualified pension plan.

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17. Segments and Related Information

PSCo has two reportable segments, regulated electric utility and regulated natural gas utility.

· PSCo’s regulated electric utility segment generates, transmits and distributes electricity in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.

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

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

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of PSCo.

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

· Directly assigned wherever applicable;

· Allocated based on cost causation allocators wherever applicable; or

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

The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which is separately determined for each segment.

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2009
Operating revenues from external customers	$	2,678,578	$	1,093,959	$	35,772		$	—		$	3,808,309
Intersegment revenues	266		79		—			(345		)	—
Total revenues	$	2,678,844	$	1,094,038	$	35,772		$	(345	)	$	3,808,309

Depreciation and amortization	$	200,776	$	50,795	$	4,491		$	—		$	256,062
Interest charges and financing costs	121,434		25,242		1,120			(36		)	147,760
Income tax expense (benefit)	123,047		57,375		(10,017		)	—			170,405
Net income	242,265		67,288		13,767			—			323,320

2008
Operating revenues from external customers	$	2,982,929	$	1,373,732	$	36,383		$	—		$	4,393,044
Intersegment revenues	229		100		—			(329		)	—
Total revenues	$	2,983,158	$	1,373,832	$	36,383		$	(329	)	$	4,393,044

Depreciation and amortization	$	190,544	$	55,638	$	6,202		$	—		$	252,384
Interest charges and financing costs	110,263		25,505		465			(186		)	136,047
Income tax expense (benefit)	132,315		53,075		(18,762		)	—			166,628
Net income	230,417		87,505		21,874			—			339,796

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	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2007
Operating revenues from external customers	$	2,605,388	$	1,186,106	$	36,006		$	—		$	3,827,500
Intersegment revenues	183		29		—			(212		)	—
Total revenues	$	2,605,571	$	1,186,135	$	36,006		$	(212	)	$	3,827,500

Depreciation and amortization	$	184,367	$	56,313	$	6,552		$	—		$	247,232
Interest charges and financing costs	97,208		24,311		46,169			(782		)	166,906
Income tax expense (benefit)	134,671		35,482		(35,796		)	—			134,357
Net income (loss)	241,955		81,348		(26,409		)	—			296,894

18. Related Party Transactions

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

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries. See Note 4 for further discussion of this borrowing arrangement.

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

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

Accounts receivable and payable with affiliates at Dec. 31, was:

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

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19. Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:

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

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

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

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

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2009, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2009 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

Item 9B — Other Information

None.

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PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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

Item 14 — Principal Accountant Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits and Financial Statement Schedules

1. Consolidated Financial Statements:

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

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

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

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

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

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

3. Exhibits

		*Indicates incorporation by reference
		+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

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

Dated as of	Previous Filing: Form; Date or file no.	Exhibit No.

Nov. 1, 1993	S-3, (33-51167)	4(b)(2)
Jan. 1, 1994	10-K, 1993	4(b)(3)
Sept. 2, 1994	8-K, September 1994	4(b)
May 1, 1996	10-Q, June 30, 1996	4(b)
Nov. 1, 1996	10-K, 1996 (001-03280)	4(b)(3)
Feb. 1, 1997	10-Q, March 31, 1997 (001-03280)	4(a)
April 1, 1998	10-Q, March 31, 1998 (001-03280)	4(b)
Aug. 15, 2002	10-Q, Sept. 30, 2002 (001-03280)	4.03
Sept. 1, 2002	8-K, Sept. 18, 2002(001-03280)	4.01
Sept. 15, 2002	10-Q, Sept. 30, 2002(001-03280)	4.04
March 1, 2003	S-3, April 14, 2003 (333-104504)	4(b)(3)
April 1, 2003	10-Q May 15, 2003 (001-03280)	4.02
May 1, 2003	S-4, June 11, 2003 (333-106011)	4.9
Sept. 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.02
Sept. 15, 2003	Xcel 10-K, March 15, 2004 (001-03034)	4.100
Aug. 1, 2005	PSCo 8-K, Aug. 18, 2005 (001-03280)	4.02
Aug. 1, 2007	PSCo 8-K, Aug. 14, 2007 (001-03280)	4.01

Table of Contents

4.03*	Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.04*	Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*	Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U. S. Bank Trust NA, as successor Trustee. (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
4.06*	Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $300,000,000 principal amount of 5.80% First Mortgage Bonds, Series No. 18 due 2018 and $300,000,000 principal amount of 6.50% First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
4.07*	Supplemental Indenture dated as of May 1, 2009 between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $400,000,000 principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+	New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008)
10.06*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+	Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+	Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement of Xcel Energy Form (file no. 001-03034) dated April 11, 2005).
10.14*+	Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement of Xcel Energy Form (file no. 001-03034) dated April 11, 2005).
10.15*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*+	First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.17*+	First Amendment to the Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009 (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10I(1)).
10.19*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10I(2)).
10.20*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.21*	Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).

Table of Contents

SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2009, 2008 and 2007

(amounts in thousands of dollars)

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

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

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

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	6
ELECTRIC UTILITY OPERATIONS	6
Overview	6
Public Utility Regulation	7
Capacity and Demand	8
Energy Sources and Related Transmission Initiatives	8
Fuel Supply and Costs	9
Fuel Sources	10
Wholesale Commodity Marketing Operations	10
Summary of Recent Regulatory Developments	10
Electric Operating Statistics	11
NATURAL GAS UTILITY OPERATIONS	12
Public Utility Regulation	12
Capability and Demand	12
Natural Gas Supply and Costs	13
Natural Gas Operating Statistics	13
ENVIRONMENTAL MATTERS	14
EMPLOYEES	14
Item 1A — Risk Factors	14
Item 1B — Unresolved Staff Comments	21
Item 2 — Properties	22
Item 3 — Legal Proceedings	22
Item 4 — Reserved	23

PART II	23
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6 — Selected Financial Data	23
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	26
Item 8 — Financial Statements and Supplementary Data	29
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
Item 9A — Controls and Procedures	74
Item 9B — Other Information	74

PART III	75
Item 10 — Directors, Executive Officers and Corporate Governance	75
Item 11 — Executive Compensation	75
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
Item 13 — Certain Relationships and Related Transactions, and Director Independence	75
Item 14 — Principal Accountant Fees and Services	75

PART IV	75
Item 15 — Exhibits and Financial Statement Schedules	75

SIGNATURES	79

10.22*	Amendment dated as of April 13, 2009 to the PSCo Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.23*	Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.24*+	Second Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.25*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy. Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.26*+	Second Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.27*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.28*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

	PUBLIC SERVICE COMPANY OF COLORADO

	/s/ DAVID M. SPARBY
	David M. Sparby
	Vice President and Chief Financial Officer
	(Principal Financial Officer)

/s/ DAVID L. EVES		/s/ RICHARD C. KELLY
David L. Eves		Richard C. Kelly
President, Chief Executive Officer and Director		Chairman and Director
(Principal Executive Officer)

/s/ TERESA S. MADDEN		/s/ DAVID M. SPARBY
Teresa S. Madden		David M. Sparby
Vice President and Controller		Vice President and Chief Financial Officer
(Principal Accounting Officer)		(Principal Financial Officer)

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Director