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, 2008

	Or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-03280

PUBLIC SERVICE COMPANY OF COLORADO

(Exact name of registrant as specified in its charter)

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.

o Yes x 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 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	o Accelerated 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). oYes x No

As of March 2, 2009, 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 2009 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*
NSP-Minnesota		Northern States Power Co., a Minnesota corporation
NSP-Wisconsin		Northern States Power Co., a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
PSRI		PSR Investments, Inc.
SPS		Southwestern Public Service Co., a New Mexico corporation
utility subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy		Xcel Energy Inc., a Minnesota corporation

*Federal and State Regulatory Agencies*
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. Federal Energy Regulatory Commission and government authorities in Canada, to develop and enforce reliability standards.
OCC		Colorado Office of Consumer Counsel
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. The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The current ECA mechanism expired Dec. 31, 2006. Effective Jan. 1, 2007 the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism will be revised quarterly

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	and interest will accrue monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.
GCA	Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
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 December 2010.
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.
TCR	Transmission cost recovery.

*Other Terms and Abbreviations*
AFDC	Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
ARO	Asset Retirement Obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
BART	Best Available Retrofit Technology
CO2	Carbon dioxide
CAMR	Clean Air Mercury Rule
COLI	Corporate-owned life insurance.
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	·	An underlying and a notional amount or payment provision or both,
	·	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
	·	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
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
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator

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Moody’s		Moody’s Investor Services Inc.
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.
PBRP		Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PUHCA		Public Utility Holding Company Act of 2005. Successor to the Public Utility Holding Company Act of 1935, enacted to regulate the corporate structure and financial operations of utility holding companies. Eliminates most federal regulation of utility holding companies. Transfers other regulatory authority from the SEC to the FERC.
rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur dioxide
SPP		Southwest Power Pool, Inc.
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)
Watt		A measure of power production or usage.
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.

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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 22 percent of its total sales in 2008. 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 2008. Generally, PSCo’s earnings range from approximately 40 percent to 50 percent of Xcel Energy’s consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns 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 2008, 2007 and 2006 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 or 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 focused on many different aspects of its operations. 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’s electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. Numerous states have proposed or implemented clean energy policies, such as renewable energy portfolio standards or DSM programs, in part designed to reduce the emissions of GHGs. Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies and regulations. PSCo is advocating with state and federal policy makers for climate change and clean energy policies that will result in significant long-term reduction in GHG emissions, develop low-emitting technologies and secure, cost-effective energy supplies for our customers and our nation.

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 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.

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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 and the transmission of electricity 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. It also includes an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive cannot exceed $11.25 million in any year. The ECA mechanism is revised quarterly. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

· PCCA — The PCCA allows for recovery of purchased capacity payments for most power purchase agreements. The PCCA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 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.

· DSMCA — The DSMCA clause permits PSCo to recover DSM and interruptible service option credit (ISOC) costs and performance initiatives based on achieving various energy savings goals on an annual basis beginning Jan. 1, 2009.

· Renewable Energy Standard Adjustment (RESA) — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2.0 percent of the customer’s total bill.

· Wind Energy Service Adjustment — The Wind Energy Service Adjustment provides for the recovery of costs associated with wind energy resources from those customers subscribed to the WindSource® program.

· 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.

Performance-Based Regulation 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 2009, assuming normal weather, is listed below.

System Peak Demand (in MW)
2006	2007	2008	2009 Forecast
6,757	6,950	6,903	6,958

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The peak demand for PSCo’s system typically occurs in the summer. The 2008 uninterrupted system peak demand for PSCo occurred on Aug. 1, 2008.

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 expansion of existing generation.

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 from such generating source.

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

PSCo Resource Plan — PSCo estimates it will purchase approximately 35 to 45 percent of its total electric system energy needs for 2009 under long-term contracts and generate the remainder with PSCo-owned resources. In November 2007, PSCo filed the Colorado Resource Plan (CRP), which details the type and amount of resources that will be added to the system for an eight year Resource Acquisition Period (RAP) through 2015. The CPUC issued its order in September 2008, which approved 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;

· Approximately 200 MW from a central solar thermal facility with storage, with possible option of acquiring up to 600 MW of solar thermal resources with storage as technology develops;

· 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 percent below 2005 levels and for PSCo to propose additional reductions to achieve a 20 percent reduction by 2020 in its next plan.

In April 2008, the CPUC approved a certificate of public convenience and necessity application to build a new, company owned 260 MW combustion turbine project at the existing Fort St. Vrain generating station. Fort St. Vrain is scheduled to come online in the second quarter of 2009. The Fort St. Vrain project will leave PSCo 123 MW short of the necessary peaking power and 16 percent short of reserve margin necessary to meet the 2009 summer peak load. PSCo will meet the differential for the summer 2009 peak by purchasing short-term capacity.

Construction continues on Comanche 3, a 750 MW pulverized coal-fired unit at the existing Comanche Station located near Pueblo, Colo. and installation of additional emission control equipment on the two existing Comanche Station units. Completion is planned for the fall of 2009. As part of an electric rate case, PSCo is allowed to include construction work in progress associated with the Comanche 3 project in rate base without an offset for AFDC, depending upon PSCo’s senior unsecured debt rating.

PSCo has an agreement with Intermountain Rural Electric Association (IREA) and Holy Cross which transfers a portion of capacity ownership in the Comanche 3 unit to IREA and Holy Cross. IREA will take ownership of 190 MW and Holy Cross will take ownership of 60 MW upon commercial operation.

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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 by 2010,

· 15 percent of retail sales by 2015,

· 20 percent of retail sales by 2020, and

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

The new 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.

PSCo Regulatory Policy Initiative — In March 2008 open meetings, the CPUC voted to open an investigatory docket that will review the current regulatory structure to determine if current utility incentives are aligned with state public policy objectives and to determine if the existing structure is internally consistent in achieving these objectives. In June 2008, a transmission investigatory docket was opened to gather information on transmission planning in Colorado and transmission planning coordination with other states and utilities was opened. In September 2008, the CPUC opened a customer incentives docket whose scope covers how regulatory structure and incentives influence customer decisions.

Several parties, including PSCo, filed comments in the utility incentive docket in September 2008. The comments covered a wide array of issues, including the best method to deliver DSM services to customers and the implications to utilities of owned generation or generation acquired through power purchase agreements. The comments also raised questions regarding whether or not revisions should be made to the current regulatory structure to reduce regulatory lag.

ISOC Program — In November 2007, PSCo submitted a request to the CPUC for permission to expand its ISOC program to make it available to customers without demand history, drop the threshold for participation to 300 KW, allow customers to control load through their energy management system, increase credits and allow customers to limit the number of interruptions in a day. PSCo also sought approval for current recovery of those credits through the DSM adjustment clause. Lastly, PSCo sought authority to recover an incentive in addition to receiving reimbursement of the credits paid to customers to reward it for successful implementation of a program that reduces overall costs to its retail customers. In June 2008, the ALJ assigned to the case approved expansion of the program and removed current recovery and incentives from the current case. The CPUC upheld the ALJ’s recommendation through an initial decision. Three parties filed a request for rehearing, reargument or reconsideration on limited issues. The CPUC granted the request and held deliberations on Oct. 15, 2008. In its final order, the CPUC approved expansion of the program, higher credits and concurrent recovery effective Jan. 1, 2009.

RESA — In December 2008, PSCo filed a request with the CPUC to increase the RESA to a full 2 percent in order to increase renewables to levels that comply with the 20 percent renewable energy requirement. The CPUC approved the request and the increase became effective on Jan. 1, 2009.

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 Fuel
	Cost		Percent		Cost		Percent		Cost
2008	$	1.42	84	%	$	7.03	16	%	$	2.31
2007	1.26		84		4.34		16		1.76
2006	1.24		85		6.52		15		2.01

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

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Fuel Sources

Coal — Coal inventory levels may vary widely among plants. PSCo normally maintains approximately 35 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2008 and 2007, were approximately 32 and 41 days usage, 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 2008 and 2007, PSCo’s coal requirements for existing plants were approximately 11 million and 10 million tons, respectively.

PSCo has contracted for coal suppliers to supply 100 percent of its coal requirements in 2009, 49 percent of its coal requirements in 2010 and 34 percent of its coal requirements in 2011. Any remaining requirements will be filled through a request for proposal process.

PSCo has coal transportation contracts that provide for delivery of approximately 100 percent of its coal requirements 2009, 93 percent of its coal requirements in 2010 and 93 percent of its coal requirements in 2011. Coal delivery may be subject to short-term interruptions or reductions due to operation of 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 provide an adequate supply of fuel. The supply contracts expire in 2009 and 2010. The transportation and storage contracts expire in various years from 2009 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, 2008, PSCo’s commitments related to supply contracts were approximately $137 million and transportation and storage contracts were approximately $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 PSCo. State and local agencies have jurisdiction over many of PSCo’s 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 repealed PUHCA effective Feb. 8, 2006 and required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act. Since August 2005, the FERC has completed a number of rulemaking proceedings to modify its regulations on a number of subjects, including:

· Adopting regulations requiring NERC to establish mandatory electric reliability standards; and

· Certifying approximately 120 NERC reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance. The FERC also approved certain WECC regional reliability standards as mandatory, which are applicable to PSCo.

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 these new rules and regulations as they become effective.

Electric Reliability Standards Matters — In June 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 audit team issued its confidential final audit report. The report found a possible violation of one standard related to relay maintenance. The audit report will now be subject to additional WECC procedures to determine if violations occurred and, if so, the consequences of such a finding.

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In response to information identified during the audit, Xcel Energy conducted a comprehensive review of the maintenance records for all relay devices on the PSCo transmission system. That review found PSCo did not have documentation demonstrating that all relay devices on the PSCo system had been maintained on the schedule in Xcel Energy’s adopted maintenance plan. In June 2008, PSCo filed a self-report regarding the maintenance plan violations with the WECC. In addition, in April 2008, PSCo filed a self-report with WECC indicating that certain tests of generation station batteries had not been completed in accordance with Xcel Energy’s adopted maintenance plan for generation station relays and batteries. In September 2008, as a result of a review of Xcel Energy’s procedures implementing certain NERC Critical Infrastructure Protection standards applicable to control centers effective July 1, 2008, PSCo filed a self-report with the WECC disclosing certain deficiencies in requirements applicable to access to critical infrastructure assets for the period July to September 2008. PSCo filed a mitigation plan with the WECC within 30 days of the self-report discussing how the deficiencies were corrected.

Xcel Energy is uncertain if the WECC audit report findings or the self-reports of reliability standards violations will result in financial penalties being imposed on PSCo. If so, the penalties are not expected to be material.

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 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. PSCo is currently participating with other utilities in the development of WestConnect, which is expected to provide certain regionalized transmission services in the first quarter of 2009 and may provide wholesale energy market functions in the future, but would not be an RTO.

In February 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules. In December 2007, the FERC issued an order on rehearing (Order No. 890-A) making certain modifications to Order No. 890, effective in March 2008. In June 2008, the FERC issued a further order on rehearing (Order No. 890-B) making certain additional modifications to Order Nos. 890 and 890-A effective in September 2008. PSCo has submitted several compliance filings to modify its OATT to reflect the modified FERC rules.

Certain transmission service customers objected to aspects of the Xcel Energy Order No. 890, 890-A and 890-B compliance filings. The various compliance filings are pending final FERC action.

Under Order No. 890, transmission providers are required to post certain information on their OASIS systems. In June 2008, the FERC initiated an audit of PSCo’s Order No. 890 OASIS compliance postings. PSCo was one of several electric utilities notified that the FERC was commencing such an audit. In November 2008, the FERC issued an order requiring certain compliance actions but did not impose financial penalties. PSCo concurred with the audit report, and the audit is now completed.

The FERC issued proposed rules to modify the current standards of conduct rules governing the functional separation of the Xcel Energy electric transmission function from the wholesale sales and marketing function. On Oct. 16, 2008, the FERC issued revised final rules. On Dec. 15, 2008, the FERC extended the compliance deadline for certain compliance actions to Jan. 30, 2009. PSCo is taking actions to be compliant with the revised rules.

Market Based Rate Rules — In June 2007, the FERC issued a final order governing its market-based rate authorizations to electric utilities. The FERC reemphasized its commitment to market-based pricing, but is revising the tests it uses to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has market-based rate authorizations. Each of the Xcel Energy utility subsidiaries has been granted market-based rate authority and will be subject to the new rule. The Xcel Energy utility subsidiaries may not sell power at market-based rates within the PSCo and SPS balancing authorities, where they have been found to have market power under the FERC’s applicable analysis. Both PSCo and SPS have cost-based coordination tariffs that they may use to make sales in their balancing authorities.

The FERC’s market rate orders allow mitigated utilities such as PSCo and SPS to sell at their borders at market-based rates subject to certain conditions. Requests for rehearing addressing that aspect of the FERC’s market-based rate orders are presently pending. Because PSCo makes such border sales, Xcel Energy sought such clarification from the FERC. The outcome of the rehearing request may impact the Xcel Energy utilities subsidiaries’ continued ability to make such border sales at market-based rates.

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Affiliate Transaction Rules — On Feb. 21, 2008, the FERC issued Order No. 707, which amended the FERC’s regulations to codify restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated power sales affiliates or non-utility affiliates. The Xcel Energy utility subsidiaries are subject to the new rules. The rules apply historic SEC “at cost” pricing standards to transactions between service companies of utility holding company systems and their FERC jurisdictional public utility affiliates. In September 2008, the National Rural Electric Cooperative Association and the American Public Power Association filed a petition for review of Order No. 707 with the U.S. Court of Appeals for the District of Columbia. The appeal is pending.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, Division of Investigations (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 and responded to the DOI allegations. 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,
	2008			2007			2006
Electric sales (millions of Kwh)
Residential	8,905			8,904			8,557
Commercial and industrial	19,137			18,947			18,398
Public authorities and other	229			235			243
Total retail	28,271			28,086			27,198
Sales for resale	7,756			8,913			7,820
Total energy sold	36,027			36,999			35,018

Number of customers at end of period
Residential	1,142,106			1,126,019			1,113,293
Commercial and industrial	150,826			149,179			147,349
Public authorities and other	58,195			58,559			60,381
Total retail	1,351,127			1,333,757			1,321,023
Wholesale	35			51			49
Total customers	1,351,162			1,333,808			1,321,072

Electric revenues (thousands of dollars)
Residential	$	914,531		$	801,162		$	756,701
Commercial and industrial	1,514,652			1,266,800			1,251,390
Public authorities and other	44,066			41,426			38,775
Total retail	2,473,249			2,109,388			2,046,866
Wholesale	457,623			438,120			408,859
Other electric revenues	52,057			57,880			49,720
Total electric revenues	$	2,982,929		$	2,605,388		$	2,505,445

Kwh sales per retail customer	20,924			21,058			20,589
Revenue per retail customer	$	1,831		$	1,582		$	1,549
Residential revenue per Kwh	10.27		¢	9.00		¢	8.84		¢
Commercial and industrial revenue per Kwh	7.91			6.69			6.80
Wholesale revenue per Kwh	5.90			4.92			5.23

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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 customer by residential customers as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 1998 to 2008, average annual sales to the typical PSCo residential customer declined from 92 MMBtu per year to 82 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.

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 monthly 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 quality of service plan. See further discussion under Item 1 — Electric Utility Operations.

Kinder Morgan Interstate Gas Transmission Bypass Pipeline — In August 2007, Kinder Morgan Interstate Gas Transmission LLC (KMIGT) filed an application with the FERC for authorizations to construct and operate 41.4 miles of 12-inch pipeline in Weld County, Colo. The purpose of this pipeline, referred to as the “Colorado Lateral,” is to provide interstate gas transportation services of up to 55,000 dekatherms per day to supply natural gas to Atmos Energy Corporation’s (Atmos) gas distribution system serving retail customers in and around Greeley and Eaton, Colo. PSCo currently provides gas transportation services to Atmos to supply its distribution system in the Greeley and Eaton areas. PSCo’s services would be bypassed by the new KMIGT pipeline, resulting in a loss of annual revenues of approximately $3.8 million. In February 2008, the FERC issued its order approving KMIGT’s application for the Colorado Lateral project.

PSCo filed a complaint at the CPUC, requesting that the CPUC enter an order finding that Atmos must cease and desist any further construction activity on the Colorado Lateral project that is under the jurisdiction of the CPUC until such time as it applies for and is granted a certificate of public convenience and necessity “CPCN”. In September 2008, an ALJ issued an order that the proposed construction of the bypass laterals is not in the normal course of business and ordered Atmos to file a CPCN application for CPUC consideration and approval.

In his recommended decision, the ALJ determined that Atmos’ 11-mile section of the “Colorado Lateral” would require that Atmos obtain a CPCN prior to the facilities being placed into service and that the doctrine of regulatory monopoly does not apply to the gas transportation service provided by PSCo, a local distribution company (LDC), to a downstream LDC such as Atmos. Therefore, Atmos has no expectation of service from PSCo and PSCo has no obligation to serve Atmos under the doctrine of regulated monopoly. The CPUC has confirmed the ALJ’s ruling in deliberations on Feb. 5, 2009, but has not yet issued a final written order at this time.

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, to be 1,874,731 MMBtu. In addition, firm transportation customers hold 598,660 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,473,391 MMBtu per day. The maximum daily deliveries for PSCo in 2008 for firm and interruptible services were 1,889,099 MMBtu on Dec. 15, 2008.

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Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2008		2007		2006
Natural gas deliveries (thousands of MMBtu)
Residential	96,871		93,664		87,200
Commercial and industrial	41,121		40,216		37,923
Total retail	137,992		133,880		125,123
Transportation and other	115,923		117,240		121,501
Total deliveries	253,915		251,120		246,624

Number of customers at end of period
Residential	1,186,255		1,169,306		1,154,598
Commercial and industrial	99,425		98,053		96,787
Total retail	1,285,680		1,267,359		1,251,385
Transportation and other	4,313		4,110		3,945
Total customers	1,289,993		1,271,469		1,255,330

Natural gas revenues (thousands of dollars)
Residential	$	941,077	$	808,738	$	866,176
Commercial and industrial	368,143		313,805		342,404
Total retail	1,309,220		1,122,543		1,208,580
Transportation and other	64,512		63,563		53,715
Total natural gas revenues	$	1,373,732	$	1,186,106	$	1,262,295

MMBtu sales per retail customer	107.33		105.64		99.99
Revenue per retail customer	$	1,018	$	886	$	966
Residential revenue per MMBtu	9.71		8.63		9.93
Commercial and industrial revenue per MMBtu	8.95		7.80		9.03
Transportation and other revenue per MMBtu	0.56		0.54		0.44

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, 2008 was 2,772. Of these full-time employees, 2,159, or 78 percent, are covered under collective bargaining agreements. See Note 9 in 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

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.

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We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate 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 and the sale of electric energy in interstate commerce.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our expenses incurred in a test year. Thus, the rates we are allowed to charge may or may not match our expenses 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 debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

We are subject to capital market risk.

PSCo’s operations require significant capital investment in property, plant and equipment; consequently, PSCo is 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, as evidenced by the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent PSCo from issuing new securities or cause PSCo 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 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.

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PSCo may at times have direct credit exposure in its 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. PSCo 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.

PSCo does 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 PSCo to exercise its contractual rights.

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

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. We utilize quoted observable market prices to the maximum extent possible in determining the value of these derivative commodity instruments. For positions for which observable market prices are not available, we utilize observable quoted market prices of similar assets or liabilities or indirectly observable prices based on forward price curves of similar markets. For positions for which we have unobservable market prices, we incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions 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.

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, 2008, these sites included:

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

· Third party sites, such as landfills, at 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.

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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 and we may 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. PSCo does not serve any coastal communities so the possibility of sea level rises does not directly affect PSCo or its 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 the company’s service territory could also have an impact on PSCo’s revenues. PSCo buys and sells 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 PSCo’s service territories, primarily through thunderstorms, tornadoes and snow or ice storms. 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 PSCo’s revenues. PSCo’s 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, 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, 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 PSCo to receive less than ideal terms and conditions.

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 create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act. PSCo’s 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. PSCo is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with our environmental leadership strategy.

Many of the federal and state climate change legislative proposals 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 emissions for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on PSCo and its 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. An important factor is PSCo’s ability to recover

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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 PSCo. 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 regarding 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 Markets risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which 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.

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, and 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.

The insurance industry has also been affected by these events and the availability of insurance covering risks our competitors and we 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 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 or the actions of a neighboring utility. 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.

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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 the firm to maintain day-to-day operations in response to unforeseen events, such as those in the preceding section, which describes numerous disruptions to our normal operating environment. 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, the 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.

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.

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

We have defined benefit 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 any changes in governmental regulations. In addition, the Pension Protection Act of 2006, as amended, 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.

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

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

As of Dec. 31, 2008, Xcel Energy had approximately $7.7 billion of long-term debt and $1.0 billion of short-term debt and current maturities. Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2008, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18.2 million of exposure. Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of Dec. 31, 2008, was approximately $27.9 million. Xcel Energy’s total exposure under these indemnities cannot be determined at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy. In 2008, 2007 and 2006 we paid $271.0 million, $263.9 million and $195.6 million of dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board

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of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs. This could adversely affect our liquidity. The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved SEC Staff Comments

None.

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:

			Summer 2008 Net
			Dependable
Station, City and Unit	Fuel	Installed	Capability (MW)

*Steam:*
Arapahoe-Denver, CO 2 Units	Coal	1951-1955	153
Cameo-Grand Junction, CO 2 Units	Coal	1957-1960	73
Cherokee-Denver, CO 4 Units	Coal	1957-1968	717
Comanche-Pueblo, CO 2 Units	Coal	1973-1975	660
Craig-Craig, CO 2 Units	Coal	1979-1980	83	(a)
Hayden-Hayden, CO 2 Units	Coal	1965-1976	238	(b)
Pawnee-Brush, CO	Coal	1981	505
Valmont-Boulder, CO	Coal	1964	186
Zuni-Denver, CO 2 Units	Natural Gas/Oil	1948-1954	91

*Combustion Turbine:*
Fort St. Vrain-Platteville, CO 4 Units	Natural Gas	1972-2001	695
Various Locations 6 Units	Natural Gas	Various	174

*Hydro:*
Various Locations 12 Units		Various	32
Cabin Creek-Georgetown, CO Pumped Storage		1967	210

*Wind:*
Ponnequin-Weld County, CO		1999-2001	25	(c)

*Diesel:*
Cherokee-Denver, CO 2 Units	Natural Gas/Oil	1967	6
		Total	3,848

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

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

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2008:

Conductor Miles
345 KV		958
230 KV		11,420
138 KV		92
115 KV		4,870
Less than 115 KV		72,582

PSCo had 219 electric utility transmission and distribution substations at Dec. 31, 2008.

Natural gas utility mains at Dec. 31, 2008:

Miles
Transmission		2,300
Distribution		21,090

Item 3 — Legal Proceedings

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

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, see Public Utility Regulation and Summary of Recent Federal Regulatory Developments under Item 1 and Note 14 to the consolidated financial statements.

Item 4 — Submission of Matters to a Vote of Security Holders

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).

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 debt agreements and FERC rules. PSCo’s mortgage bonds prohibit dividends or other similar distributions unless covenants relating to PSCo’s capitalization are met. 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 2008 and 2007 were as follows:

Quarter Ended (Thousands of Dollars)
March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008
$	68,144	$	67,111	$	67,258	$	67,417

Quarter Ended (Thousands of Dollars)
March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007
$	65,514	$	65,774	$	67,792	$	68,454

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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.

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. 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, 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; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of PSCo’s Form 10-K for the year ended Dec. 31, 2008.

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

Results Of Operations

PSCo’s net income was approximately $339.8 million for 2008, compared with approximately $296.9 million for 2007. During 2007, PSCo settled an ongoing dispute with the U.S. government regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. The resolution of this dispute resulted in a reduction of net income of approximately $36.1 million in 2007. For further discussion see Note 8 to the consolidated financial statements.

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)	2008			2007
Electric revenues	$	2,983		$	2,605
Electric fuel and purchased power	(1,819		)	(1,436		)
Electric margin	$	1,164		$	1,169

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

Electric Revenues

(Millions of Dollars)	2008 vs 2007
Fuel and purchased power cost recovery	$	364
RESA rider	19
Retail sales growth (excluding weather impact)	12
Conservation and non-fuel riders	10
Trading revenues	10
Revenues due to leap year (weather-normalized)	3
Firm wholesale	(25		)
Estimated impact of weather	(11		)
Other	(4		)
Total increase in electric revenues	$	378

Electric Margin

(Millions of Dollars)	2008 vs 2007
Firm wholesale	$	(15	)
Estimated impact of weather	(11		)
Trading margin	(6		)
Transmission revenues, net of expense	(6		)
Retail sales growth (excluding weather impact)	12
Conservation and non-fuel riders	10
Purchased capacity costs	5
Margin due to leap year (weather-normalized)	3
Other	3
Total decrease in electric margin	$	(5	)

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)	2008			2007
Natural gas revenues	$	1,374		$	1,186
Cost of natural gas sold and transported	(994		)	(832		)
Natural gas margin	$	380		$	354

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)	2008 vs 2007
GCA recovery	$	163
Base rate changes	19
Retail sales growth (excluding weather impact)	5
Revenues due to leap year (weather-normalized)	1
Estimated impact of weather	(1		)
Other	1
Total increase in natural gas revenues	$	188

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Natural Gas Margin

(Millions of Dollars)	2008 vs 2007
Base rate changes	$	19
Retail sales growth (excluding weather impact)	5
Revenues due to leap year (weather-normalized)	1
Estimated impact of weather	(1		)
Other	2
Total increase in natural gas utility margin	$	26

Non-Fuel Operating Expenses and Other Items

Other Operating and Maintenance Expenses — The following summarizes the components of the changes in other operating and maintenance expenses for the year ended Dec. 31:

(Millions of Dollars)	2008 vs 2007
Lower employee benefit costs	$	(17	)
Lower donation costs	(4		)
Lower employee expenses	(2		)
Higher plant generation costs	6
Higher labor costs	6
Higher consulting costs	4
Higher lease costs	3
Higher allowance for bad debts	2
Total decrease in other operating and maintenance expenses	$	(2	)

DSM — DSM expense increase by approximately $15.0 million for 2008 compared with 2007. The higher expense is attributable to the ongoing expansion of such programs as designed, in part, to meet certain regulatory commitments in our various jurisdictions.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $5.1 million, or 2.1 percent, for 2008 compared with 2007, primarily due to planned system expansion.

Interest and Other Income (Expense), net — Interest and other income (expense), net, increased by approximately $19.1 million for 2008 compared with 2007, primarily due to PSRI’s termination of the COLI program in 2007, which eliminated certain expenses.

Interest Charges and Financing Costs — Interest charges and financing costs decreased by approximately $25.9 million, or 14.4 percent, for 2008 compared with 2007, primarily due to interest incurred related to the COLI life insurance settlement, partially offset set by an increase in long-term debt balances.

AFDC — AFDC increased by approximately $26.9 million for 2008 compared with 2007, primarily due to the ongoing construction of Comanche 3, which was partially offset by the current recovery from customers of the financing costs related to this construction through base rates, resulting in a lower recognition of AFDC.

Income Taxes — Income tax expense increased by approximately $32.3 million for 2008 compared with 2007. The effective tax rate was 32.9 percent for 2008, compared with 31.2 percent for 2007. The increase in income tax expense and the higher effective tax rate for 2008 were primarily due to an increase in pretax income.

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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. These risks, as applicable to PSCo, 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 the company’s use of commodity derivatives. Though no material non-performance risk currently exists with the counterparties to PSCo’s commodity derivative contracts, the continued turmoil in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Continued distress in the financial markets may also impact the fair value of the master pension trust, as well as PSCo’s ability to earn a return on short-term investments of excess cash. Also, the current state of the financial markets may negatively impact PSCo’s ability to obtain debt financing under favorable terms.

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, as allowed by regulation.

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. These marketing activities generally have terms of less than one year in length. 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.

The fair value of the commodity trading contracts at Dec. 31, were as follows:

(Thousands of Dollars)	2008			2007
Fair value of commodity trading contract assets (liabilities) outstanding at Jan. 1	$	3,937		$	(620	)
Contracts realized or settled during the period	626			(1,865		)
Fair value of commodity trading contract additions and changes during the period	(4,009		)	6,422
Fair value of commodity trading contract assets outstanding at Dec. 31	$	554		$	3,937

At Dec. 31, 2008, the fair values by source for the commodity trading net asset balances were as follows:

	Futures/Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/ Forwards Fair Value
	1	$	(804	)	$	—	$	—	$	—	$	(804	)
	2	1,358			—		—		—		1,358
Total Futures/Forwards Fair Value		$	554		$	—	$	—	$	—	$	554

(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 SFAS No. 133 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.

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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.

VaR is calculated on a consolidated basis. The VaRs for the commodity trading operations were:

	Year ended				During 2008
(Millions of Dollars)	Dec. 31, 2008		VaR Limit		Average		High		Low
Commodity trading (a)	$	0.30	$	5.00	$	0.30	$	1.14	$	0.01

	Year ended				During 2007
(Millions of Dollars)	Dec. 31, 2007		VaR Limit		Average		High		Low
Commodity trading (a)	$	0.26	$	5.00	$	0.47	$	1.45	$	0.09

(a) Includes transactions for NSP-Minnesota and PSCo.

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, subject to regulatory approval when required.

At Dec. 31, 2008, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $0.8 million.

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

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. The recent volatility in financial markets could increase our credit risk.

At Dec. 31, 2008, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $0.8 million, while a decrease of 10 percent would have resulted in a decrease of $0.1 million.

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PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2008			2007			2006
Operating revenues
Electric	$	2,982,929		$	2,605,388		$	2,505,445
Natural gas	1,373,732			1,186,106			1,262,295
Steam and other	36,383			36,006			38,089
Total operating revenues	4,393,044			3,827,500			3,805,829

Operating expenses
Electric fuel and purchased power	1,818,772			1,435,680			1,489,714
Cost of natural gas sold and transported	994,221			831,826			938,380
Cost of sales — steam and other	15,507			15,646			21,043
Other operating and maintenance expenses	605,008			607,467			569,059
Demand-side management program expenses	32,990			18,010			15,860
Depreciation and amortization	252,384			247,232			224,056
Taxes (other than income taxes)	84,597			85,261			88,878
Total operating expenses	3,803,479			3,241,122			3,346,990

Operating income	589,565			586,378			458,839

Interest and other income (expense), net	16,748			(2,400		)	(14,223		)
Allowance for funds used during construction — equity	36,158			14,179			2,650

Interest charges and financing costs
Interest charges — includes other financing costs of $5,754, $5,599 and $6,029, respectively	154,313			180,230			137,493
Allowance for funds used during construction — debt	(18,266		)	(13,324		)	(13,386		)
Total interest charges and financing costs	136,047			166,906			124,107

Income before income taxes	506,424			431,251			323,159
Income taxes	166,628			134,357			81,701
Net income	$	339,796		$	296,894		$	241,458

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
	2008			2007			2006
Operating activities
Net income	$	339,796		$	296,894		$	241,458
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	293,863			272,850			253,725
Deferred income taxes	85,875			79,359			76,040
Amortization of investment tax credits	(2,760		)	(3,869		)	(3,949		)
Allowance for equity funds used during construction	(36,158		)	(14,179		)	(2,650		)
Allowance for bad debts	28,372			26,149			26,944
Net realized and unrealized hedging and derivative transactions	(19,012		)	2,583			(19,497		)
Changes in operating assets and liabilities:
Accounts receivable	(10,469		)	(71,005		)	106,747
Accrued unbilled revenues	5,665			(160,830		)	35,253
Inventories	(24,028		)	29,673			34,865
Recoverable purchased natural gas and electric energy costs	6,535			143,970			72,566
Prepayments and other	3,438			(3,198		)	(2,591		)
Accounts payable	(607		)	73,108			(187,571		)
Deferred purchased natural gas and electric energy costs	78,719			30,132			(1,313		)
Net regulatory assets and liabilities	(10,310		)	26,021			(36,008		)
Other current liabilities	3,700			10,585			20,569
Change in other noncurrent assets	436			(15,878		)	(2,154		)
Change in other noncurrent liabilities	(47,743		)	(44,964		)	(29,893		)
Net cash provided by operating activities	695,312			677,401			582,541

Investing activities
Capital/construction expenditures	(809,738		)	(806,794		)	(537,920		)
Allowance for equity funds used during construction	36,158			14,179			2,650
Investments in utility money pool arrangement	(439,500		)	(721,700		)	(5,600		)
Receipts from utility money pool arrangement	540,100			621,100			5,600
Other investments	23,716			(4,451		)	9,869
Net cash used in investing activities	(649,264		)	(897,666		)	(525,401		)

Financing activities
Proceeds from (repayment of) short-term borrowings — net	(231,007		)	(101,493		)	36,896
Proceeds from issuance of long-term debt	592,389			343,711			—
Repayment of long-term debt, including reacquisition premiums	(301,445		)	(101,379		)	(126,334		)
Borrowings under utility money pool arrangement	755,600			486,500			1,426,800
Repayments under utility money pool arrangement	(714,600		)	(486,500		)	(1,426,800		)
Capital contributions from parent	127,529			347,924			227,272
Dividends paid to parent	(270,966		)	(263,859		)	(195,625		)
Net cash provided by (used in) financing activities	(42,500		)	224,904			(57,791		)

Net increase (decrease) in cash and cash equivalents	3,548			4,639			(651		)
Cash and cash equivalents at beginning of year	7,650			3,011			3,662
Cash and cash equivalents at end of year	$	11,198		$	7,650		$	3,011

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	131,098		$	130,709		$	125,284
Cash paid for income taxes (net of refunds received)	90,187			61,718			(6,640		)

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	16,379		$	10,902		$	5,367

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, 2008		Dec. 31, 2007
Assets
Current assets:
Cash and cash equivalents	$	11,198	$	7,650
Investments in utility money pool arrangement	—		100,600
Accounts receivable, net	362,401		375,265
Accounts receivable from affiliates	29,545		34,584
Accrued unbilled revenues	354,526		360,191
Inventories	233,948		209,920
Deferred income taxes	64,181		59,564
Derivative instruments valuation	22,793		33,635
Prepayments and other	15,110		31,708
Total current assets	1,093,702		1,213,117

Property, plant and equipment, net	7,592,111		7,029,155

Other assets:
Regulatory assets	943,012		539,989
Derivative instruments valuation	119,534		141,410
Other	46,610		55,759
Total other assets	1,109,156		737,158
Total assets	$	9,794,969	$	8,979,430

Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	201,510	$	301,445
Short-term debt	40,000		271,007
Borrowings under utility money pool arrangement	41,000		—
Accounts payable	470,158		466,710
Accounts payable to affiliates	28,906		27,445
Deferred purchased natural gas and electric energy costs	113,276		34,411
Taxes accrued	72,105		76,569
Dividends payable to parent	67,417		68,453
Derivative instruments valuation	28,776		21,521
Accrued interest	50,542		45,486
Other	78,192		74,568
Total current liabilities	1,191,882		1,387,615

Deferred credits and other liabilities:
Deferred income taxes	1,204,861		1,090,740
Deferred investment tax credits	52,406		55,166
Regulatory liabilities	514,445		516,401
Pension and employee benefit obligations	527,264		231,232
Customer advances	290,937		280,270
Derivative instruments valuation	62,126		84,190
Asset retirement obligations	61,505		44,267
Other	22,491		12,063
Total deferred credits and other liabilities	2,736,035		2,314,329

Commitments and contingent liabilities
Capitalization:
Long-term debt	2,289,251		1,891,644
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—		—
Additional paid in capital	2,886,657		2,759,128
Retained earnings	683,516		614,267
Accumulated other comprehensive income	7,628		12,447
Total common stockholder’s equity	3,577,801		3,385,842
Total liabilities and equity	$	9,794,969	$	8,979,430

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			Additional Paid in		Retained			Accumulated Other Comprehensive			Total Common Stockholder’s
	Shares	Amount		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2005	100	$	—	$	2,183,932	$	604,163		$	(106,106	)	$	2,681,989
Net income						241,458						241,458
Minimum pension liability adjustment, net of tax of $19,239									31,589			31,589
Net derivative instrument fair value changes during the period, net of tax of $(981)									(1,607		)	(1,607		)
Unrealized gain — marketable securities, net of tax of $(46)									(75		)	(75		)
Comprehensive income for 2006												271,365
SFAS No. 158 adoption, net of tax of $53,995									88,813			88,813
Common dividends declared to parent						(260,402		)				(260,402		)
Contribution of capital by parent				227,272								227,272
Balance at Dec. 31, 2006	100	$	—	$	2,411,204	$	585,219		$	12,614		$	3,009,037
FIN 48 adoption						(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
EITF 06-4 adoption, 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

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
	2008			2007
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2008, 4.375%	$	—		$	300,000
Oct. 1, 2012, 7.875%	600,000			600,000
March 1, 2013, 4.875%	250,000			250,000
April 1, 2014, 5.5%	275,000			275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Aug. 1, 2018, 5.8%	300,000			—
Jan. 1, 2019, 5.1% (a)	48,750			48,750
Sept. 1, 2037, 6.25%	350,000			350,000
Aug. 1, 2038, 6.5%	300,000			—
Unsecured Senior A Notes, due July 15, 2009, 6.875%	200,000			200,000
Capital lease obligations, 11.2% due in installments through 2028	43,423			44,868
Unamortized discount	(5,912		)	(5,029		)
Total	2,490,761			2,193,089
Less current maturities	201,510			301,445
Total long-term debt	$	2,289,251		$	1,891,644

Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2008 and 2007	$	—		$	—
Additional paid in capital	2,886,657			2,759,128
Retained earnings	683,516			614,267
Accumulated other comprehensive income	7,628			12,447
Total common stockholder’s equity	$	3,577,801		$	3,385,842

(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 purchased natural gas and electric fuel and 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 recovers all prudently incurred electric fuel and purchased energy costs through the ECA for the company’s retail jurisdiction. The ECA is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA includes an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism is revised quarterly and interest accrues monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

· PSCo generally recovers all purchased capacity costs through the PCCA for the company’s retail jurisdiction. The PCCA mechanism is revised annually.

· PSCo’s rates include annual adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually. 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 SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133). 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 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 commodity derivatives, the most observable inputs available are generally used to determine

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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.

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 SFAS No. 133, 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 sales 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; vehicle fuel costs are recorded as a component of capital project 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 designation of a cash flow hedge permits changes in fair value to be recorded within other comprehensive income (OCI), to the extent the hedge is effective, or deferred as a regulatory asset or liability.

SFAS No. 133 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 SFAS No. 133. 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 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. SFAS No. 133 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 from SFAS No. 133 as normal purchases or normal sales.

PSCo evaluates all of its contracts at inception to determine if they are derivatives and, if so, if they qualify to meet the normal purchases and normal sales designation requirements under SFAS No. 133. 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

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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 include costs associated with property held for future use.

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, 2008, 2007 and 2006 was 2.7 percent, 2.7 percent and 2.6 percent, respectively.

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

Environmental Costs — Environmental costs are recorded on an undiscounted basis 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 under FAS 109, 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 turn around, or 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.

In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, PSCo adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

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PSCo reports interest and penalties related to income taxes within the interest charges section 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.

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.

Restricted Cash — At Dec. 31, 2007, PSCo had restricted cash of $23.7 million. The restricted cash balance primarily represents deposits held in conjunction with short-term wholesale and commodity trading activities. This balance is presented as a component of other assets on the consolidated balance sheets.

Inventory — All inventories are recorded at average cost.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with statement of financial accounting standards SFAS No. 71 — Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Under SFAS No. 71:

· 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 include deferred financing costs, net of amortization, of approximately $16.4 million and $12.7 million at Dec. 31, 2008 and 2007, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

Debt premiums, discounts, expenses and amounts received or paid to settle hedges are amortized over the life of the related debt. The premiums and costs associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. If PSCo extinguishes the debt, all unamortized balances shall be expensed at the time of the redemption.

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) — 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 Renewable Portfolio Standards (RPS)

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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 the load obligation, they are recorded as inventory at actual cost. RECs acquired for trading purposes are recorded as other investments at actual cost. The cost of RECs that are retired for compliance purposes are 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.

Reclassifications — DSM program expenses were reclassified as a separate item from depreciation and amortization on the consolidated statements of income. Activity from the allowance for bad debts was reclassified from the change in accounts receivable on the consolidated statements of cash flows. These reclassifications did not have an impact on total operating expenses or net cash provided by operating activities.

2. Accounting Pronouncements

Recently Issued

Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, 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. SFAS No. 141R 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 will apply SFAS No. 141R to business combinations occurring subsequent to Jan. 1, 2009.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, 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 statement is effective for fiscal years and interim periods beginning on or after Dec. 15, 2008. PSCo does not expect the implementation of SFAS No. 160 to have a material impact on its consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, 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. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged. PSCo does not expect the implementation of SFAS No. 161 to have a material impact on its consolidated financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) — In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand on an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk. FSP FAS 132(R)-1 is effective for fiscal years ending

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after Dec. 15, 2009. PSCo does not expect the implementation of FSP FAS 132(R)-1 to have a material impact on its consolidated financial statements.

Recently Adopted

Fair Value Measurements (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.

On Jan. 1, 2008, PSCo adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2, Effective Date of FASB Statement No. 157. The adoption did not have a material impact on PSCo’s consolidated financial statements. For additional discussion and SFAS No. 157 required disclosures, see Note 13 to the consolidated financial statements.

The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement was effective for fiscal years beginning after Nov. 15, 2007. PSCo adopted SFAS No. 159 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (FSP FAS 157-3) — In October 2008, the FASB issued FSP FAS 157-3, which clarifies the application of SFAS No. 157 in a market that is not active. FSP FAS 157-3 was effective immediately upon issuance, and applied to prior periods for which financial statements had not yet been issued. PSCo adopted FSP FAS 157-3 as of Sept. 30, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) — In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods. Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer. EITF No. 06-4 was effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted. Upon adoption of EITF No. 06-4 on Jan. 1, 2008, PSCo recorded a liability of $0.6 million, net of tax, as a reduction of retained earnings. Thereafter, changes in the liability are reflected in operating results.

Amendment of FASB Interpretation No. 39 (FSP FIN 39-1) — In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts, to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP FIN 39-1 was effective for fiscal years beginning after Nov. 15, 2007. PSCo adopted FSP FIN 39-1 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) — In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital. The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. EITF No. 06-11 was to be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that were declared in fiscal years beginning after Dec. 15, 2007. PSCo adopted EITF No. 06-11 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

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The Hierarchy of GAAP (SFAS No. 162) — In May 2008, the FASB issued SFAS No. 162, which establishes the GAAP hierarchy, identifying the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements. SFAS No. 162 was effective Nov. 15, 2008. PSCo adopted SFAS No. 162 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities (FSP FAS 140-4 and FIN 46(R)-8) — In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to require public entities to provide additional disclosures about transfers of financial assets. It also amends FIN 46 (revised December 2003), Consolidation of Variable Interest Entities, to require public enterprises, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures about their involvement with variable interest entities. FSP FAS 140-4 and FIN 46(R)-8 was effective for the interim and annual periods ending after Dec. 15, 2008. PSCo adopted FSP FAS 140-4 and FIN 46(R)-8 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2008			Dec. 31, 2007
Accounts receivable, net:
Accounts receivable	$	391,596		$	398,566
Less allowance for bad debts	(29,195		)	(23,301		)
	$	362,401		$	375,265

Inventories:
Materials and supplies	$	40,451		$	40,409
Fuel	41,456			40,811
Natural gas	152,041			128,700
	$	233,948		$	209,920

Property, plant and equipment, net:
Electric utility plant	$	7,089,763		$	6,633,695
Natural gas utility plant	1,914,565			1,887,824
Common utility and other property	739,453			726,049
Construction work in progress	1,086,627			864,517
Total property, plant and equipment	10,830,408			10,112,085
Less accumulated depreciation	(3,238,297		)	(3,082,930		)
	$	7,592,111		$	7,029,155

4. Short-Term Borrowings

Commercial Paper — At Dec. 31, 2008 and 2007, PSCo had commercial paper outstanding of approximately $40.0 million and $271.0 million, respectively. PSCo has board approval to issue up to $700 million of commercial paper. The weighted average interest rates at Dec. 31, 2008 and 2007, were 1.55 percent and 5.64 percent, respectively.

Money Pool — Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. PSCo has approval to borrow up to $250 million under the arrangement. At Dec. 31, 2008 and 2007, PSCo had money pool borrowings of $41.0 million and money pool loans outstanding of $100.6 million, respectively. The weighted average interest rates at Dec. 31, 2008 and 2007, were 3.48 percent and 5.64 percent, respectively.

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5. Long-Term Debt

Credit Facilities — At Dec. 31, 2008, PSCo had the following committed credit facility in effect, in millions of dollars:

Credit

Facility

Credit Facility

Borrowings

Available*

Original
Term

Maturity

675.1

—

630.2

Five year

December 2011

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

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 with which PSCo was in compliance at Dec. 31, 2008 and 2007. 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.

· 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. The commitment fees are calculated for the unused portion of the credit facility at 8 basis points for PSCo.

· 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.

· At Dec. 31, 2007, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $271.0 million of commercial paper outstanding and $5.1 million of letters of credit.

Long-Term Borrowings

On Aug. 13, 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.

On Aug. 15, 2007, PSCo issued $350 million of 6.25 percent first mortgage bonds, series due Sept. 1, 2037. PSCo added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper, including commercial paper incurred to fund the payment at maturity of $100 million of 7.11 percent secured medium-term notes, which matured on March 5, 2007.

Maturities of long-term debt are:

(Millions of Dollars)
2009	$	201.5
2010	1.6
2011	1.6
2012	601.7
2013	251.8

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6. Preferred Stock

PSCo has authorized the issuance of preferred stock.

Preferred Shares			Preferred 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, 2008:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Hayden Unit 1	$	88,386	$	54,319	$	411	75.5
Hayden Unit 2	81,504		51,680		2,047		37.4
Hayden Common Facilities	31,563		11,479		414		53.1
Craig Units 1 and 2	53,421		31,334		358		9.7
Craig Common Facilities, Units 1, 2 and 3	33,205		14,058		456		6.5 - 9.7
Comanche Unit 3	—		—		672,144		66.7
Transmission and other facilities, including substations	141,119		52,803		529		11.6 - 68.1
Total	$	429,198	$	215,673	$	676,359

PSCo’s current operational assets include approximately 320 MW of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for funding 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 3, is expected to be completed in the fall of 2009. PSCo is the operating agent under the joint ownership agreement.

8. Income Taxes

COLI — As previously disclosed, 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. In September 2007, Xcel Energy and the United States finalized a settlement, which terminated the tax litigation pending between the parties. 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.

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. Xcel Energy paid the settlement as follows:

· $32.2 million was satisfied by tax and interest amounts that Xcel Energy had previously paid or deemed under the terms of the settlement to have been paid.

· $32.2 million was paid by Xcel Energy on Oct. 31, 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.

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Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — PSCo is a member of the Xcel Energy affiliated group that files consolidated income tax returns. In the first quarter of 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. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009. In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of Dec. 31, 2008, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

As of Dec. 31, 2008, PSCo’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

The amount of unrecognized tax benefits was $8.8 million and $10.3 million on Dec. 31, 2007 and 2008, respectively. A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2008			2007
Balance at Jan. 1	$	8.8		$	11.4
Additions based on tax positions related to the current year	2.9			3.0
Reductions based on tax positions related to the current year	(0.5		)	—
Additions for tax positions of prior years	2.0			33.2
Reductions for tax positions of prior years	(0.2		)	(0.8		)
Settlements with taxing authorities	—			(38.0		)
Lapse of applicable statute of limitations	(2.7		)	—
Balance at Dec. 31	$	10.3		$	8.8

These unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss and tax credit carryovers of $3.8 million and $5.8 million as of Dec. 31, 2007 and 2008, respectively.

The unrecognized tax benefit balance included $2.8 million and $1.4 million of tax positions on Dec. 31, 2007 and 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $6.0 million and $8.9 million of tax positions on Dec. 31, 2007 and 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 increase in the unrecognized tax benefit balance of $1.5 million from Dec. 31, 2007 to Dec. 31, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity, partially offset by a decrease due to the expiration of statutes of limitations. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when 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.

The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with net operating loss and tax credit carryovers. The amount of interest expense related to unrecognized tax benefits reported within interest charges in 2007 was $44.8 million. The amount of interest income related to unrecognized tax benefits reported within interest charges in 2008 was $3.4 million. The liability for interest related to unrecognized tax benefits was $3.8 and $0.4 million on Dec. 31, 2007 and 2008.

The amount of penalty expense related to unrecognized tax benefits reported within interest charges in 2007 was $3.2 million. The liability for penalties related to unrecognized tax benefits was $1.0 million on Dec. 31, 2007. In 2008, the liability for penalties related to unrecognized tax benefits was reversed and a $1.0 million benefit was reported within interest charges in 2008. No amounts were accrued for penalties as of Dec. 31, 2008.

Other Income Tax Matters — PSCo’s federal net operating loss carryforward is estimated to be $40.1 million and $102.6 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. PSCo’s federal tax credit carryforward is estimated to be $12.1 million and $11.1 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. The carryforward periods expire between 2021 and 2028. PSCo also has a state net operating loss carryforward of $63.6 million and $72.3 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively, and state tax credit carryforwards of $5.8 million and $4.4 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. The state carryforward periods expire between 2016 and 2027.

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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 is a table reconciling such differences for the years ending Dec. 31:

	2008		2007		2006
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	1.7		1.2		4.3
Regulatory differences — utility plant items	(2.2	)	(0.8	)	0.2
Life insurance policies	(0.2	)	(7.2	)	(10.3	)
Tax credits recognized, net of federal income tax expense	(1.1	)	(1.6	)	(1.9	)
Resolution of income tax audits and other	0.3		(1.8	)	(1.0	)
FIN 48 expense — unrecognized tax benefits	(0.3	)	6.6		—
Other, net	(0.3	)	(0.2	)	(1.0	)
Effective income tax rate	32.9	%	31.2	%	25.3	%

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

(Thousands of Dollars)	2008			2007			2006
Current federal tax expense (benefit)	$	77,865		$	29,496		$	(2,691	)
Current state tax expense (benefit)	6,219			(2,077		)	12,301
Current FIN 48 tax (benefit) expense	(571		)	31,448			—
Deferred federal tax expense	81,326			78,508			71,756
Deferred state tax expense	8,859			7,414			6,807
Deferred FIN 48 tax benefit	(841		)	(2,782		)	—
Deferred tax credits	(3,469		)	(3,781		)	(2,523		)
Deferred investment tax credits	(2,760		)	(3,869		)	(3,949		)
Total income tax expense	$	166,628		$	134,357		$	81,701

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

(Thousands of Dollars)	2008			2007
Deferred tax expense excluding items below	$	109,504		$	89,940
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(26,540		)	(10,226		)
FIN 48 adoption: Deferred tax benefit reported as an adjustment to the beginning balance of retained earnings	—			(447		)
Tax expense allocated to other comprehensive income and other	2,911			92
Deferred tax expense	$	85,875		$	79,359

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

(Thousands of Dollars)	2008		2007
Deferred tax liabilities:
Differences between book and tax bases of property	$	1,176,313	$	1,075,552
Deferred costs	35,442		66,899
Regulatory assets	52,728		44,974
Employee benefits	33,819		24,940
Other	17,024		6,252
Total deferred tax liabilities	$	1,315,326	$	1,218,617

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Deferred tax assets:
Unbilled revenues	$	78,175	$	74,134
Net operating loss carry forward	24,420		43,814
Tax credit carry forward	17,931		15,560
Deferred investment tax credits	19,891		20,875
Regulatory liabilities	16,166		14,057
Bad debts	11,082		8,817
Rate refunds	3,678		8,362
Other	3,303		1,822
Total deferred tax assets	$	174,646	$	187,441
Net deferred tax liability	$	1,140,680	$	1,031,176

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 offers various benefit plans to its employees, including those of PSCo. Approximately 50 percent of Xcel Energy employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2008, PSCo had 2,159 bargaining employees covered under a collective-bargaining agreement, which expires in May 2009.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. PSCo applied regulatory accounting treatment for unrecognized amounts of regulated utility subsidiary employees, which allowed recognition as a regulatory asset rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates. The effect of adopting in 2006 for the remaining unrecognized amounts was an increase in accumulated other comprehensive income of $88.8 million.

Pension Benefits

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

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 52 percent in equity investments, 25 percent in fixed income investments and 23 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.

The actual composition of pension plan assets at Dec. 31 was:

	2008		2007
Equity securities	55	%	60	%
Debt securities	26		22
Real estate	5		4
Cash	3		2
Nontraditional investments	11		12
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers 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.

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The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 9.56 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments. A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2008 and 2007 were below the assumed level of 8.75 percent while returns in 2006 exceeded the assumed level of 8.75 percent. Xcel Energy continually reviews its pension assumptions. In 2009, Xcel Energy will use an investment-return assumption of 8.50 percent.

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)	2008			2007
Accumulated Benefit Obligation at Dec. 31	$	2,435,513		$	2,497,898

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,662,759		$	2,666,555
Service cost	62,698			61,392
Interest cost	167,881			162,774
Plan amendments	—			(19,955		)
Actuarial (gain) loss	(47,509		)	23,325
Benefit payments	(247,797		)	(231,332		)
Obligation at Dec. 31	$	2,598,032		$	2,662,759

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	3,186,273		$	3,183,375
Actual (loss) return on plan assets	(788,273		)	199,230
Employer contributions	35,000			35,000
Benefit payments	(247,797		)	(231,332		)
Fair value of plan assets at Dec. 31	$	2,185,203		$	3,186,273

Funded Status of Plans at Dec. 31:
Funded status	$	(412,829	)	$	523,514
Noncurrent assets	15,612			568,055
Noncurrent liabilities	(428,441		)	(44,541		)
Net pension amounts recognized on consolidated balance sheets	$	(412,829	)	$	523,514

PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	394,045		$	156,521
Prior service cost	17,287			20,122
Total	$	411,332		$	176,643
SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	411,332		$	176,643
Total	$	411,332		$	176,643

PSCo accrued benefit liability recorded	$	251,178		$	39,781

Measurement Date	Dec. 31, 2008			Dec. 31, 2007

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.75		%	6.25		%
Expected average long-term increase in compensation level	4.00			4.00
Mortality table	RP 2000			RP 2000

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At Dec. 31, 2008, one of Xcel Energy’s pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million. At Dec. 31, 2007, the plan assets of $369.8 million exceeded projected benefit obligations of $253.6 million. All other Xcel Energy plans in the aggregate had plan assets of $1.9 billion and $2.8 billion and projected benefit obligations of $2.4 billion and $2.4 billion on Dec. 31, 2008 and 2007.

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 2006 through 2008 for Xcel Energy’s pension plans and are not expected to require cash funding in 2009.

· Voluntary contributions were made to the PSCo Bargaining Pension Plan of $35 million in 2008, $35 million in 2007 and $30 million in 2006.

· Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $2 million in 2006. No voluntary contributions were made to the plan during 2007 or 2008.

· Xcel Energy projects cash funding of $70 million to $130 million in 2009. Pension funding contributions for 2010, 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 $150 million to $250 million.

Plan Changes — The Pension Protection Act of 2006 (PPA) was effective Dec. 31, 2006. PPA requires a change in the conversion basis for lump-sum payments and three-year vesting for plans with account balance or pension equity benefits. These changes are reflected as a plan amendment for purposes of SFAS No. 87, Employers’ Accounting for Pensions.

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

(Thousands of Dollars)	2008			2007			2006
Service cost	$	62,698		$	61,392		$	61,627
Interest cost	167,881			162,774			155,413
Expected return on plan assets	(274,338		)	(264,831		)	(268,065		)
Amortization of prior service cost	20,584			25,056			29,696
Amortization of net loss	11,156			15,845			17,353
Net periodic pension (credit) cost under SFAS No. 87	$	(12,019	)	$	236		$	(3,976	)

PSCo:
Net periodic pension cost	$	11,120		$	18,348		$	18,666

Significant Assumptions Used to Measure Costs:
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term increase in compensation level	4.00			4.00			3.50
Expected average long-term rate of return on assets	8.75			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 2009 pension cost calculations will be 8.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy 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 also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo were approximately $6.1 million in 2008, $7.9 million in 2007 and $6.2 million in 2006.

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Postretirement Health Care Benefits

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy 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 conjunction with the 1993 adoption of SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pension, Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 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 SFAS No. 106 costs. PSCo is required to fund SFAS No. 106 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 non-bargaining 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.

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

	2008		2007
Equity and equity mutual fund securities	49	%	67	%
Fixed income/debt securities	29		21
Cash equivalents	22		11
Nontraditional investments	—		1
	100	%	100	%

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

(Thousands of Dollars)	2008			2007
Change in Benefit Obligation:
Obligation at Jan. 1	$	830,315		$	918,693
Service cost	5,350			5,813
Interest cost	51,047			50,475
Medicare subsidy reimbursements	6,178			2,526
Plan participants’ contributions	13,892			13,211
Actuarial gain	(46,827		)	(86,576		)
Benefit payments	(65,358		)	(73,827		)
Obligation at Dec. 31	$	794,597		$	830,315

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	427,459		$	406,305
Actual (loss) return on plan assets	(132,226		)	24,623
Plan participants’ contributions	13,892			13,211
Employer contributions	55,799			57,147
Benefit payments	(65,358		)	(73,827		)
Fair value of plan assets at Dec. 31	$	299,566		$	427,459

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Funded Status at Dec. 31:
Funded status	$	(495,031	)	$	(402,856	)
Current liabilities	(4,928		)	(1,755		)
Noncurrent liabilities	(490,103		)	(401,101		)
Net amounts recognized on consolidated balance sheets	$	(495,031	)	$	(402,856	)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	181,157		$	74,361
Prior service credit	(1,757		)	(2,185		)
Transition obligation	44,801			55,805
Total	$	224,201		$	127,981

SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	224,201		$	127,981
Total	$	224,201		$	127,981

PSCo accrued benefit liability recorded	$	254,003		$	161,712

	2008		2007
Measurement Date	Dec. 31, 2008		Dec. 31, 2007

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.75	%	6.25	%
Mortality table	RP 2000		RP 2000

Effective Dec. 31, 2008, Xcel Energy reduced its initial medical trend assumption from 8.0 percent to 7.4 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is five years. Xcel Energy bases its 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 Xcel Energy’s 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 at Dec. 31, 2008	$	51,475
1-percent decrease in APBO components at Dec. 31, 2008	(43,439		)
1-percent increase in service and interest components of the net periodic cost	4,526
1-percent decrease in service and interest components of the net periodic cost	(3,736		)

Plan Changes — The employer subsidy for retiree medical coverage was eliminated for former NCE non-bargaining employees who retire after July 1, 2003.

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 contributed $55.6 million during 2008 and expects to contribute approximately $63.1 million during 2009.

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

(Thousands of Dollars)	2008			2007			2006
Service cost	$	5,350		$	5,813		$	6,633
Interest cost	51,047			50,475			52,939
Expected return on plan assets	(31,851		)	(30,401		)	(26,757		)
Amortization of transition obligation	14,577			14,577			14,444
Amortization of prior service credit	(2,175		)	(2,178		)	(2,178		)
Amortization of net loss	11,498			14,198			24,797
Net periodic postretirement benefit cost under SFAS No. 106	$	48,446		$	52,484		$	69,878
PSCo:
Net periodic postretirement benefit cost recognized — SFAS No. 106	26,989			28,661			39,976
Additional cost recognized due to effects of regulation	3,891			3,891			3,891
Net cost recognized for financial reporting	$	30,880		$	32,552		$	43,867

Significant assumptions used to measure costs (income):
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term rate of return on assets (pretax)	7.50			7.50			7.50

Projected Benefit Payments

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.

			Gross Projected				Net Projected
			Postretirement Health				Postretirement Health
	Projected Pension		Care Benefit		Expected Medicare		Care Benefit
(Thousands of Dollars)	Benefit Payments		Payments		Part D Subsidies		Payments
2009	$	224,558	$	62,975	$	5,725	$	57,250
2010	226,585		64,468		6,117		58,351
2011	226,446		66,390		6,433		59,957
2012	230,763		67,400		6,804		60,596
2013	234,149		68,008		7,127		60,881
2014-2018	1,237,114		351,249		38,796		312,453

10. Detail of Interest and Other Income (Expense), Net

Interest and other income (expense), net of nonoperating expenses, for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2008			2007			2006
Interest income	$	10,283		$	9,876		$	4,462
Other nonoperating income	2,954			2,373			2,581
Insurance policy income (expense)	3,515			(14,642		)	(20,404		)
Other nonoperating expense	(4		)	(7		)	(862		)
Total interest and other income (expense), net	$	16,748		$	(2,400	)	$	(14,223	)

11. Derivative Instruments

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. PSCo utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.

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 for generation and distribution activities. Commodity risk is also managed through the use of financial derivative instruments. PSCo utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though the regulatory jurisdiction may

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provide for recovery of actual costs. 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 these activities within guidelines and limitations as approved by the risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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 SFAS No. 133, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for PSCo 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.

Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The types of qualifying hedging transactions that PSCo is currently engaged in are discussed below.

Cash Flow Hedges

Commodity Cash Flow Hedges — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. 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. Certain derivative instruments entered into to manage this variability are designated as cash flow hedges for accounting purposes. At Dec. 31, 2008, PSCo had various commodity-related contracts designated as cash flow hedges extending through December 2010. Changes in the fair value of cash flow hedges are recorded in other comprehensive income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place.

At Dec. 31, 2008, PSCo had $4.9 million of net losses in accumulated other comprehensive income related to commodity cash flow hedge contracts; $2.8 million is expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

PSCo had immaterial ineffectiveness related to commodity cash flow hedges during 2008 and 2007.

Interest Rate Cash Flow Hedges — PSCo enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps that effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.

At Dec. 31, 2008, PSCo had net gains of approximately $1.5 million in accumulated other comprehensive income related to interest rate hedges that it expects to recognize in earnings during the next 12 months.

PSCo had no ineffectiveness related to interest rate cash flow hedges during 2008 and 2007.

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The following table shows the major components of the derivative instruments valuation in the consolidated balance sheets at Dec. 31:

	2008				2007
(Thousands of Dollars)	Derivative Instruments Valuation – Assets		Derivative Instruments Valuation – Liabilities		Derivative Instruments Valuation – Assets		Derivative Instruments Valuation – Liabilities
Long term purchased power agreements	$	137,334	$	66,986	$	155,928	$	96,654
Electricity and natural gas trading and hedging instruments	4,993		23,916		19,117		9,057
Total	$	142,327	$	90,902	$	175,045	$	105,711

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, 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 the first quarter of 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 cash flow hedges on PSCo’s accumulated other comprehensive income, included in the consolidated statements of common stockholder’s equity and comprehensive income, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	14.2
After-tax net unrealized losses related to derivative accounted for as hedges	(0.1		)
After-tax net realized gains on derivative transactions reclassified into earnings	(1.5		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006	$	12.6
After-tax net unrealized gains related to derivatives accounted for as hedges	1.3
After-tax net realized gains on derivative transactions reclassified into earnings	(1.5		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2007	$	12.4
After-tax net unrealized losses related to derivatives accounted for as hedges	(3.3		)
After-tax net realized gains on derivative transactions reclassified into earnings	(1.5		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2008	$	7.6

12. Financial Instruments

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

	2008				2007
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	2	$	2	$	23,718	$	23,718
Long-term debt, including current portion	2,490,761		2,654,256		2,193,089		2,297,047

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, 2008 and 2007. 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.

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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, 2008 and 2007, there were $4.9 million and $5.1 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 SFAS No. 157 for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 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.

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 securities or contracts, or priced with models using highly observable inputs.

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.

PSCo held several commodity derivatives measured at fair value on a recurring basis as of Dec. 31, 2008. Fair value for these commodity derivatives was primarily determined based on observable prices for similar forward contracts, or internally prepared option valuation models using observable forward curves and volatilities. For certain instruments, it may be necessary to use 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 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 at Dec. 31, 2008.

The following table presents, for each of the SFAS No. 157 hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis as of Dec. 31, 2008:

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

(a) FASB Interpretation No. 39 Offsetting of Amounts Relating to Certain Contracts, as amended by FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39, 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.

The following table presents the changes in Level 3 recurring fair value measurements for the year ended Dec. 31, 2008:

(Thousands of Dollars)	Commodity Derivatives, Net
Balance, Jan. 1, 2008	$	4,121
Purchases, issuances, and settlements, net	(4,396		)
Losses recognized in earnings	(1,384		)
Gains recognized as regulatory assets and liabilities	1,633
Balance, Dec. 31, 2008	$	(26	)

Gains 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

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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 Electric Rate Case — On Nov. 14, 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 is 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.

On Feb. 13, 2009, parties filed answer testimony in the case. The CPUC staff accepted PSCo’s forecast test-year and recommended an increase of $110 million based on a 10.37 percent ROE. The CPUC staff also recommended that the increase be split into two parts, the first part consisting of $69.9 million, effective in July 2009 and the remaining $40 million to take effect on or about Jan. 1, 2010 to coincide with the implementation of rates from the next rate case. In addition to ROE, the primary CPUC staff adjustments are related to the sales forecast, debt rate, incentive pay, and wage increases. The CPUC staff also recommends an earnings test to refund any earnings above authorized levels to customers.

The Office of Consumer Council (OCC) recommended a $3.8 million increase based on a historic test year increase of $69.9 million. The OCC recommended an ROE of 9.75 percent and an equity ratio of 53 percent. The OCC recommended adjustments to the cash working capital and rate case expense.

Other parties filing testimony affecting the revenue requirements were the Colorado Energy Consumers which supported use of a historic test year; Ratepayers United of Colorado, which recommended a 9.5 percent ROE; and Leslie Glustrom, a citizen intervenor, who raised concerns about the Comanche 3 project as well as PSCo’s consulting and personal communication costs.

A final decision is expected in the summer of 2009. The following procedural schedule has been established:

· PSCo rebuttal testimony on March 20, 2009;

· Staff and intervenor surrebuttal testimony on April 10, 2009; and

· The hearing on the merits are scheduled for April 20-May 1, 2009.

Natural Gas Rate Case — Phase II — In July 2007, the CPUC issued a final written order approving a natural gas rate increase of approximately $32.3 million, based on a 10.25 percent ROE and a 60.17 percent equity ratio. Final rates were implemented effective July 30, 2007, through a general rate schedule adjustment (GRSA) applied to all customer classes. Under the provisions of the settlement between PSCo and the CPUC, PSCo filed its Phase II (cost allocation and rate design) in April 2008 to spread the settled revenue requirement from its 2006 Phase I gas rate case among PSCo’s customer classes.

In December 2008, the CPUC issued its final order in which the CPUC approved with certain exceptions PSCo’s proposed reallocation of its revenue requirement, including the $32.3 million final written order referenced above, among rate classes.

In this same order, the CPUC rejected PSCo’s proposal to raise its fixed monthly service and facilities charges. The CPUC also approved the recovery of PSCo’s $15 million pilot low-income assistance program through customers’ service and facilities charges. The costs of this low-income program are in addition to the $32.3 million base-rate increase approved in July 2007.

On Jan. 1, 2009, PSCo implemented the CPUC’s approved reallocation of the revenue requirement, eliminated the GRSA and began recovering the costs of its low-income program.

Electric, Purchased Gas and Resource Adjustment Clauses

TCA Rider — In September 2007, PSCo filed with the CPUC a request to implement a TCA. In December 2007, the CPUC approved PSCo’s application to implement the TCA rider. The CPUC limited the scope of the costs that could be recovered through the rider during 2008 to only those costs associated with transmission investment made after the new legislation authorizing the TCA rider became effective on March 26, 2007. The CPUC also required PSCo to base its revenue

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requirement calculation on a thirteen-month average net transmission plant balance. As a result of the CPUC’s decision, PSCo implemented a rider on Jan. 1, 2008, designed to recover approximately $4.5 million in 2008. PSCo filed updates to the TCA rider on Nov. 3, 2008, and new rates went into effect on Jan. 1, 2009, to recover approximately $18.0 million on an annual basis until the time rates in the pending rate case take effect.

Enhanced DSM Program — In July 2008, the CPUC issued an order approving PSCo’s proposal to expand the DSM program and recover 100 percent of its forecasted expenses associated with the DSM program during the year in which the rider is in effect, beginning in 2009. An incentive mechanism was also approved to reward PSCo for meeting and exceeding program goals.

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 FERC has yet to act on this order on remand.

PSCo Wholesale Rate Case — In February 2008, PSCo requested a $12.5 million, or 5.88 percent, increase in wholesale rates, based on an 11.5 percent requested ROE. The $12.5 million total increase was composed of $8.8 million of traditional base rate recovery and $3.7 million of construction work in progress recovery for the Comanche 3 and Fort St. Vrain projects. The increase would be applicable to all wholesale firm service customers with the exception of Intermountain Rural Electric Cooperative, which would be under a rate moratorium until January 2009.

In March 2008, PSCo reached an agreement with Rural Electric Association (REA) customers Holy Cross, Yampa Valley and Grand Valley, which resolved all issues based on a “black box” settlement with an implied ROE of 10.4 percent. Parties filed the settlement with the FERC on April 17, 2008, with rates effective May 1, 2008. PSCo has reached an agreement with the cities of Burlington and Center, as well as Aquila under the same substantive terms and conditions as the REA settlement. This settlement was filed with the FERC on April 25, 2008. The settlements provide for:

· A traditional annual rate base rate increase of $6.6 million with AFDC continuing for Comanche Station and Fort St. Vrain.

· Implementation of new rates several months earlier than is typical in a disputed filing.

· The ability to implement rates in PSCo’s next general rate case that will involve Comanche 3 costs upon a nominal suspension.

The FERC approved the settlement agreements on June 19, 2008.

Additionally, PSCo reached a settlement with Intermountain Rural Electric Association on similar terms. The FERC approved the settlement on Dec. 29, 2008. Rates took effect on Jan. 1, 2009. This agreement will increase base rates for Intermountain by $1.7 million in 2009.

15. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2008, the estimated cost of the capital expenditure programs and other capital requirements of PSCo is approximately $610 million in 2009, $600 million in 2010 and $600 million in 2011. PSCo’s capital expenditure forecast includes the following major project:

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Comanche 3 — Comanche 3, a 750 MW coal-fired plant being built in Colorado, is expected to cost approximately $1.3 billion, with major construction initiated in 2006 and is expected to be completed in the fall of 2009. The CPUC has approved sharing one-third ownership of this plant with other parties.

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.

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 2009 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, 2008, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
		(Millions of Dollars)
$	689	$	527	$	2,086

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 2027. 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, 2008, 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)
2009	$	381.8
2010	354.9
2011	344.2
2012	288.9
2013	223.5
2014 and thereafter	1,115.6
Total	$	2,708.9

Leases — PSCo leases a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2028. 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.

Following is a summary of assets held under capital leases:

(Millions of Dollars)	2008			2007
Storage, leaseholds and rights	$	40.5		$	40.5
Gas pipeline	20.7			20.7
	61.2			61.2
Less: Accumulated amortization	(17.8		)	(16.3		)
Total assets held under capital leases	$	43.4		$	44.9

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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 $85.6 million, $44.6 million and $17.1 million for 2008, 2007 and 2006, respectively. Included in total rental expense were purchase power agreement payments of $67.5 million, $26.1 million and $0.0 million in 2008, 2007 and 2006, 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 Emerging Issues Task Force 01-8, Determining whether an Arrangement Contains a Lease and SFAS No. 13, Accounting for Leases. Future commitments under operating and capital leases are:

(Millions of Dollars)	Other Operating Leases		Purchased Power Agreement Operating Leases (a) (b)		Total Operating Leases		Capital Leases
2009	$	12.5	$	63.6	$	76.1	$	6.0
2010	12.5		59.8		72.3		5.8
2011	11.9		49.1		61.0		5.7
2012	10.6		45.0		55.6		5.5
2013	10.4		47.7		58.1		5.3
Thereafter	25.8		713.8		739.6		51.5
Total minimum obligation							79.8
Interest component of obligation							(36.4		)
Present value of minimum obligation							$	43.4

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

(b) Purchase power agreement 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 potentially responsible parties (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.

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, 2008, the liability for the cost of remediating these sites was estimated to be $1.7 million, of which $0.2 million was considered to be a current liability.

MGP Sites

Fort Collins MGP Site — Prior to 1926, the Poudre Valley Gas Co. operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the assets of the Poudre Valley Gas Co., PSCo shut down the MGP and has subsequently sold most of the property. In 2002, an oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. In November 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co. under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring.

In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years. In June 2007, PSCo entered into a settlement agreement that included recovery of the full $10.8 million, but with a five-year amortization period. The CPUC approved the agreement on June 18, 2007. The total amount to be recovered from customers is $13.1 million. Estimated future project costs, based upon an assumed 30-year system operating life, including EPA oversight costs, are approximately $2.8 million. This reflects a reduction in estimated EPA oversight costs over the life of the project, based upon the most recent EPA oversight billing.

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In April 2005, PSCo brought a contribution action against Schrader and related parties (collectively “Schrader”) alleging Schrader released hazardous substances into the environment and these releases caused MGP byproducts to migrate to the Cache la Poudre River, thereby substantially increasing the scope and cost of remediation. PSCo requested damages, including a portion of the costs PSCo incurred, to investigate and remove contaminated sediments from the Cache la Poudre River. In November 2008, PSCo and Schrader entered into a settlement agreement whereby Schrader paid $2.75 million to PSCo, and will make additional payments of $50,000 per year for the next five years for a total settlement of $3.0 million. Net proceeds from the settlement will be credited to customers.

Third Party and Other Environmental Site Remediation

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 asset retirement obligation. See additional discussion of asset retirement obligations 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

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.

The EPA required states to develop implementation plans to comply with BART by December 2007. 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 implementation of BART will cost approximately $254 million in capital costs, which includes approximately $113 million in environmental upgrades for the existing Comanche Station Units 1 and 2 project, 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 2011 and 2014. Colorado’s state implementation plan has been submitted to EPA for approval. In January 2009, the 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 stakeholder process will continue throughout 2009.

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. Colorado’s mercury rule requires mercury emission controls capable of achieving 80 percent capture 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 mercury emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.

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 challenging the phase II rulemaking. In January 2007, the court issued its decision and remanded virtually every aspect of 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 court-ordered remand. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. 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. A decision is not expected until 2009.

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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 Clean Air Act (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 FASB Statement No. 143, Accounting for Asset Retirement Obligations, (SFAS No. 143). 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 pursuant to SFAS No. 71.

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. In addition, an ARO was recognized 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.

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, 2008 and 2007, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2008		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2008
Electric Utility 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
Gas Utility Plant:
Gas transmission and distribution	29,926		—		—		741		(30,088		)	579
Total liability	$	44,267	$	8,505	—		$	1,646	$	7,087		$	61,505

PSCo incurred revisions to prior estimates and new liabilities for asbestos due to a new dismantling cost study. There were also revised gas distribution, ash ponds and electric transmission and distribution asset retirement obligations due to new estimates and end of life dates.

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(Thousands of Dollars)	Beginning Balance Jan. 1, 2007		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2007
Electric Utility Plant:
Steam production asbestos	$	9,634	$	—	$	—	$	567	$	—		$	10,201
Steam production ash containment	3,906		—		—		241		(89		)	4,058
Electric transmission and distribution	593		—		—		13		(524		)	82
Gas Utility Plant:
Gas transmission and distribution	29,202		—		—		724		—			29,926
Total liability	$	43,335	$	—	—		$	1,545	$	(613	)	$	44,267

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 under SFAS No. 71. Removal costs as of Dec. 31, 2008 and Dec. 31, 2007 were $379 million and $374 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.

Environmental Litigation

Carbon Dioxide Emissions Lawsuit — In July 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, 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. In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. 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. In June 2007 the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S. Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA. In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy 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

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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. In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments were presented to the Court of Appeals on Aug. 6, 2008. Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 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. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that Defendants’ emission of CO2 and other greenhouse gases (GHG) contribute to global warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million. Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim. 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. The matter has now been fully briefed, with oral arguments set for May 19, 2009. It is unknown when the court will render a decision.

Employment, Tort and Commercial Litigation

Qwest vs. Xcel Energy Inc. — In June 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. Pursuant to this agreement, Qwest asserted PSCo had an affirmative duty to properly train and instruct its employees on pole safety, including testing the pole for soundness before climbing. In May 2006, PSCo filed a counterclaim against Qwest asserting Qwest had a duty to PSCo and an obligation under the contract to maintain its poles in a safe and serviceable condition. 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 June 16, 2008, Qwest filed its appellate brief. The matter has been fully briefed by the parties and oral arguments were presented on Feb. 18, 2009. PSCo is currently awaiting a decision by the court.

Mallon vs. Xcel Energy Inc. — In August 2007, Xcel Energy, PSCo and PSRI 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, Xcel Energy, PSCo and PSRI 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 PSCo, Xcel Energy Inc. and PSRI. In January 2009, the court granted defendant Mallon’s motion to amend his answer to, among other things, add a counterclaim for breach of contract and fraud against plaintiffs PSRI, PSCo and Xcel Energy. Xcel Energy believes the counterclaims are without merit and intend to vigorously defend against them.

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. This work was being performed as part of a corrosion prevention effort. A fire occurred inside the penstock, which is a 4,000-foot long, 12-foot wide pipe used to deliver water from a reservoir to the hydro facility. Four of the nine RPI employees working inside the penstock were positioned below the fire and were able to exit the pipe. The remaining five RPI employees were unable to exit the penstock. Rescue crews located the five employees a few hours later and 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 indicated an extension of the stay is possible. A lawsuit has been 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 are 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

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Creek. A second lawsuit (Ledbetter et. al vs. PSCo et. al) has also been 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, and it is anticipated that the plaintiff will refile the lawsuit in Colorado. Xcel Energy, Inc and PSCo intend to vigorously defend themselves against the claims asserted in all three lawsuits.

16. Regulatory Assets and Liabilities

PSCo’s consolidated financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the consolidated financial statements. Under SFAS No. 71, 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 use SFAS No. 71 accounting. If changes in the utility industry or the business of PSCo no longer allow for the application of SFAS No. 71 under GAAP, PSCo would be required to recognize the write-off of regulatory assets 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	Amortization Period	2008		2007
Regulatory Assets
Current regulatory asset — Unrecovered fuel costs	1	Less than one year	$	697	$	13,857

Pension and other employee benefit obligations	9	Various	$	655,563	$	328,137
Conservation programs (a)		Various	75,543		78,415
AFDC recorded in plant (a)		Plant lives	65,382		44,913
Contract valuation adjustments (b)	11	Term of related contract	60,903		22,931
Net asset retirement obligations		Plant lives	25,983		15,545
Losses on reacquired debt	1	Term of related debt	20,486		22,404
Environmental costs	15	Four to five years	11,542		15,174
Renewable resource costs		One to two years	10,319		5,273
Purchased power contracts costs	11	Term of related contract	7,487		—
Rate case costs	1	Various	1,248		1,523
Other		Various	8,556		5,674
Total noncurrent regulatory assets			$	943,012	$	539,989

Regulatory Liabilities
Current regulatory liability — Overrecovered fuel costs			$	113,276	$	34,411

Plant removal costs	15		$	378,863	$	374,213
Contract valuation adjustments			71,675		59,275
Investment tax credit deferrals			32,061		33,471
Deferred income tax adjustments			23,743		28,403
Gain on sale of emission allowances			5,093		18,031
Other			3,010		3,008
Total noncurrent regulatory liabilities			$	514,445	$	516,401

(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.

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.

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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.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
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
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
2006
Operating revenues from external customers	$	2,505,445	$	1,262,295	$	38,089		$	—		$	3,805,829
Intersegment revenues	201		90		—			(291		)	—
Total revenues	$	2,505,646	$	1,262,385	$	38,089		$	(291	)	$	3,805,829
Depreciation and amortization	$	163,860	$	53,663	$	6,533		$	—		$	224,056
Interest charges and financing costs	95,674		26,984		1,750			(301		)	124,107
Income tax expense (benefit)	93,429		30,049		(41,777		)	—			81,701
Net income	$	170,997	$	57,475	$	12,986		$	—		$	241,458

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.

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

(Thousands of Dollars)	2008		2007		2006
Operating expenses:
Other operations — paid to Xcel Energy Services Inc.	$	285,423	$	270,778	$	267,307
Interest expense	1,361		966		4,894

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

	2008				2007
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	15,987	$	—	$	17,440	$	—
NSP-Wisconsin	71		—		—		2
SPS	—		191		—		337
Other subsidiaries of Xcel Energy	13,487		28,715		17,144		27,106
	$	29,545	$	28,906	$	34,584	$	27,445

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, 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

	Quarter Ended
(Thousands of Dollars)	March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007

Operating revenues	$	1,163,691	$	835,598	$	781,261	$	1,046,950
Operating income	148,682		133,193		172,421		132,082
Net income	85,749		14,138		105,658		91,349

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

During 2007 and 2008, 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(T) — 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 Securities and Exchange Commission 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, 2008, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and the 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.

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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, 2008 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.

This annual report does not include an attestation report of PSCo’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit PSCo to provide only management’s report in this annual report.

Item 9B — Other Information

None.

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, Related Transactions and Director Independence

Item 14 — Principal Accounting 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 2009 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1. Consolidated Financial Statements:

Management Report on Internal Controls — For the year ended Dec. 31, 2008.

Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Income — For the three years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Balance Sheets — As of Dec. 31, 2008 and 2007.

2. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2008, 2007 and 2006.

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

Nov. 1, 1993	S-3, (33-51167)	4(b)(2)	Aug. 15, 2002	10-Q, Sept. 30, 2002 (001-03280)	4.03
Jan. 1, 1994	10-K, 1993	4(b)(3)	Sept. 1, 2002	8-K, Sept. 18, 2002(001-03280)	4.01
Sept. 2, 1994	8-K, September 1994	4(b)	Sept. 15, 2002	10-Q, Sept. 30, 2002(001-03280)	4.04
May 1, 1996	10-Q, June 30, 1996	4(b)	March 1, 2003	S-3, April 14, 2003 (333-104504)	4(b)(3)
Nov. 1, 1996	10-K, 1996 (001-03280)	4(b)(3)	April 1, 2003	10-Q May 15, 2003 (001-03280)	4.02
Feb. 1, 1997	10-Q, March 31, 1997 (001-03280)	4(a)	May 1, 2003	S-4, June 11, 2003 (333-106011)	4.94
April 1, 1998	10-Q, March 31, 1998 (001-03280)	4(b)	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

4.03*		Indenture dated July 1, 1999, between Public Service Co. of Colorado and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.04*		Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*		$700,000,000 Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 99.01 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 14, 2006).
4.06*		Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor Trustee. (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
4.07*		Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust National Association, 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 Public Service Company of Colorado dated Aug. 6, 2008 (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*+		Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).

Table of Contents

10.11*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+		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).
10.13*+		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).
10.14*+		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).
10.15*+		Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).
10.16*+		Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).
10.17*+		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).
10.18*+		Agreement, dated March 20, 2007 between Mr. Gary R. Johnson and Xcel Energy Inc. (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 20, 2007).
10.19*+		Letter dated Sept. 19, 2007, from Xcel Energy Inc. to the U.S. Department of Justice (DOJ) submitting its offer to settle the COLI tax dispute and Letter dated Sept. 21, 2007 from the DOJ to Xcel Energy Inc. accepting the settlement offer. (Exhibit 10.1 to Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2007).
10.20*+		Amendment Four to Employment Agreement between Xcel Energy Inc. and Paul Bonavia (Exhibit 10.02 to Xcel Energy’s Form 8-K (file no. 001-03034) dated May 23, 2007).
10.21*+		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).
10.22*+		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).
10.23*		Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between Public Service Co. of Colorado and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10I(1)).
10.24*		First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between Public Service Co. of Colorado and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10I(2)).
10.25*		Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.26*		Settlement Agreement among Public Service Co. of Colorado and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01		Consent of Independent Registered Public Accounting Firm.
31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

Table of Contents

SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2008, 2007 and 2006

(amounts in thousands of dollars)

			Additions
	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts (1)		Deductions from reserves (2)		Balance at end of period

Reserve deducted from related assets:
Allowance for bad debts:
2008	$	23,301	$	28,372	$	8,146	$	30,624	$	29,195
2007	18,415		26,149		9,582		30,845		23,301
2006	19,381		26,944		7,375		35,285		18,415

(1) Recovery of amounts previously written off

(2) Principally bad debts written off or transferred

/S/ TIM E. TAYLOR		/S/ BENJAMIN G.S. FOWKE III
Tim E. Taylor		Benjamin G.S. Fowke III
President and Chief Executive Officer		Executive Vice President and Chief Financial Officer
March 2, 2009		March 2, 2009

FORM 10-K

PUBLIC SERVICE COMPANY OF COLORADO

1225 17th Street, Denver, Colorado 80202

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

MGP Sites

Third Party and Other Environmental Site Remediation

CERTIFICATION

PSCo’s CAUTIONARY FACTORS

PART I
Item 1 — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Overview
Public Utility Regulation
Capacity and Demand
Energy Sources and Related Transmission Initiatives
Fuel Supply and Costs
Fuel Sources
Wholesale Commodity Marketing Operations
Summary of Recent Regulatory Developments
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Public Utility Regulation
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 1A — Risk Factors
Item 1B — Unresolved SEC Staff Comments
Item 2 — Properties
Item 3 — Legal Proceedings
Item 4 — Submission of Matters to a Vote of Security Holders

PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6 — Selected Financial Data
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A(T) — Controls and Procedures
Item 9B — Other Information

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

PART IV
Item 15 — Exhibits, Financial Statement Schedules

SIGNATURES

		PUBLIC SERVICE COMPANY OF COLORADO

		/s/ BENJAMIN G.S. FOWKE III
		Benjamin G.S. Fowke III
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

/s/ TIM E. TAYLOR		/s/ RICHARD C. KELLY
Tim E. Taylor		Richard C. Kelly
President, Chief Executive Officer and Director		Chairman and Director
(Principal Executive Officer)

/s/ TERESA S. MADDEN		/s/ BENJAMIN G.S. FOWKE III
Teresa S. Madden		Benjamin G.S. Fowke III
Vice President and Controller		Executive Vice President, Chief Financial Officer and Director
(Principal Accounting Officer)		(Principal Financial Officer)

	/s/ TIM E. TAYLOR
	Tim E. Taylor
	President and Chief Executive Officer
Date: March 2, 2009

2008	$	7.04
2007	5.87
2006	7.09