PUBLIC SERVICE CO OF COLORADO - FORM 10-K

Attached files

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EX-99.01 - EXHIBIT 99.01 - PUBLIC SERVICE CO OF COLORADO	ex99_01.htm
EX-12.01 - EXHIBIT 12.01 - PUBLIC SERVICE CO OF COLORADO	ex12_01.htm
EX-32.01 - EXHIBIT 32.01 - PUBLIC SERVICE CO OF COLORADO	ex32_01.htm
EX-31.01 - EXHIBIT 31.01 - PUBLIC SERVICE CO OF COLORADO	ex31_01.htm
EX-31.02 - EXHIBIT 31.02 - PUBLIC SERVICE CO OF COLORADO	ex31_02.htm
EX-23.01 - EXHIBIT 23.01 - PUBLIC SERVICE CO OF COLORADO	ex23_01.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2010

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 incorporation or organization)		(I.R.S. Employer Identification No.)

1800 Larimer, Suite 1100, Denver, Colorado 80202

(Address of principal executive offices)

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

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

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

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

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

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

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

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

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

o Large accelerated filer		oAccelerated filer

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

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

As of Feb. 28, 2011, 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 2011 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).

INDEX


PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	6
ELECTRIC UTILITY OPERATIONS	6
Overview	6
Public Utility Regulation	7
Capacity and Demand	7
Energy Sources and Related Transmission Initiatives	7
Fuel Supply and Costs	9
Fuel Sources	10
Wholesale Commodity Marketing Operations	10
Summary of Recent Regulatory Developments	10
Electric Operating Statistics	13
NATURAL GAS UTILITY OPERATIONS	13
Public Utility Regulation	13
Capability and Demand	14
Natural Gas Supply and Costs	14
Natural Gas Operating Statistics	15
ENVIRONMENTAL MATTERS	15
EMPLOYEES	15
Item 1A — Risk Factors	16
Item 1B — Unresolved Staff Comments	23
Item 2 — Properties	24
Item 3 — Legal Proceedings	25
Item 4 — Reserved	25

PART II	25
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6 — Selected Financial Data	25
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	28
Item 8 — Financial Statements and Supplementary Data	30
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	76
Item 9A — Controls and Procedures	76
Item 9B — Other Information	77

PART III	77
Item 10 — Directors, Executive Officers and Corporate Governance	77
Item 11 — Executive Compensation	77
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13 — Certain Relationships and Related Transactions, and Director Independence	77
Item 14 — Principal Accountant Fees and Services	77

PART IV	78
Item 15 — Exhibits, Financial Statement Schedules	78

SIGNATURES	82

This Form 10-K is filed by PSCo. PSCo is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

Index

PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NCE		New Century Energies, Inc.
NSP-Minnesota		Northern States Power Company, a Minnesota corporation
NSP-Wisconsin		Northern States Power Company, a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
PSRI		P.S.R. Investments, Inc., a manager of corporate-owned life insurance policies
SPS		Southwestern Public Service Company, a New Mexico corporation
utility subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
WYCO		WYCO Development LLC, a joint venture formed between Xcel Energy and Colorado Interstate Gas Company to develop and lease natural gas pipeline, storage, and compression facilities
Xcel Energy		Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
AQCC		Colorado Air Quality Control Commission
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.
CSB		U.S. Chemical Safety Board
DOI		U.S. Department of the Interior
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 FERC and government authorities in Canada, to develop and enforce reliability standards.
OCC		Office of Consumer Counsel
OSHA		Occupational Safety and Health Administration
SEC		Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
DSM		Demand side management. Energy conservation and weatherization program for low-income customers.
DSMCA		Demand side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA		Retail electric commodity adjustment. Allows PSCo to recover its actual fuel and purchased energy expense in a calendar year to a benchmark formula. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA.
GCA		Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
PCCA		Purchased capacity cost adjustment. Allows PSCo to recover from retail customers for all purchased capacity payments to power suppliers. Capacity charges are not included in PSCo’s electric rates or other recovery mechanisms.

Index

PDRA	Partial Decoupling Rate Adjustment. A clause included in PSCo’s retail natural gas schedules that recovers revenue lost to decreasing use per customer beyond a threshold.
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, 2012.
RES	Renewable energy standard
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
TCA	Transmission cost adjustment. Provides for the recovery of transmission plant revenue requirements.
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
APBO	Accumulated Postretirement Benefit Obligation
ARO	Asset retirement obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC	FASB Accounting Standards Codification
BAL	Balancing authority
BART	Best Available Retrofit Technology
BTA	Best Technology Available
CAA	Clean Air Act
CACJA	Clean Air Clean Jobs Act
CAMR	Clean Air Mercury Rule
CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
COLI	Corporate-owned life insurance
Codification	FASB Accounting Standards Codification
CPCN	Certificate of Public Convenience and Necessity
CWIP	Construction work in progress
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	●	An underlying and a notional amount or payment provision or both;
	●	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and
	●	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provide for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
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 MW (capacity) or MW hours (energy).
GHG	Greenhouse gas
JOA	Joint operating agreement among Xcel Energy’s utility subsidiaries
LIBOR	London Interbank Offered Rate
MACT	Maximum Achievable Control Technology
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MISO	Midwest Independent Transmission System Operator
Moody’s	Moody’s Investor Services

Index

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.
NAV		Notice of alleged violation
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.
NOPR		Notice of proposed rulemaking
O&M		Operating and maintenance
OCI		Other comprehensive income
PBRP		Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PCB		Polychlorinated biphenyl
PJM		PJM Interconnection, LLC
PPA		Purchased power agreement
Provident		Provident Life & Accident Insurance Company
PRP		Potentially responsible party
PV		Photovoltaic
rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
REC		Renewable energy credit
RFP		Request for proposal
ROE		Return on equity
ROFR		Right of first refusal
RPS		Renewable Portfolio Standard. A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SCR		Selective Catalytic Reduction
SIP		State Implementation Plan
SO2		Sulfur dioxide
Standard & Poor’s		Standard & Poor’s Ratings Services
unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
Underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
WECC		Western Electricity Coordinating Council
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.
KV		Kilovolts (one KV equals one thousand volts)
KW		Kilowatts (one KW equals one thousand watts)
KWh		Kilowatt hours
MMBtu		One million Btus
MW		Megawatts (one MW equals one thousand KW)
Volt		The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt		A measure of power production or usage.

Index

COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 20 percent of its total sales in 2010. 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 2010. Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. 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, income from continuing operations and related financial information are set forth in Note 15 to the consolidated financial statements for further discussion.

PSCo focuses on growing through investments in electric and natural gas rate base to 1) meet growing customer demands, 2) comply with environmental and renewable energy initiatives and 3) maintain or increase reliability and quality of service to customers. PSCo files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. Environmental leadership is a strategic priority for PSCo. Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Overview

Environmental Regulations, Climate Change and Clean Energy — Electric utilities are subject to a significant array of environmental regulations. Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.

While environmental regulations, climate change and clean energy continue to evolve, PSCo has undertaken a number of initiatives to meet current and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Although the impact of climate change policy on PSCo will depend on the specifics of state and federal policies, legislation and regulation, we believe that, based on prior state commission practice, PSCo would be granted the authority to recover the cost of these initiatives through rates.

Utility Competition — The FERC has continued 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 generation resources 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.

Transmission — In June 2010, the FERC issued a NOPR that would eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory (referred to as a ROFR). The NOPR is pending FERC action. Irrespective of the NOPR, the utility subsidiaries are pursuing several new transmission facility projects.

PSCo supports the continued development of wholesale competition and non-discriminatory wholesale open access transmission services. The FERC has approved the open access transmission planning processes for the PSCo.

Alternative Energy Options — PSCo’s 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.

Index

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices (see Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules discussion); however, PSCo withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

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

●	ECA — The ECA recovers fuel and purchase power costs. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA. The ECA mechanism is revised quarterly.

●

PCCA — The PCCA allows for recovery of purchased capacity payments for power purchase agreements. Effective January 2011, the PCCA recovers the revenue requirement associated with the purchase of two facilities formerly under power purchase agreement: Blue Spruce Energy Center and Rocky Mountain Energy Center.

●	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 January 1, as well as on an interim basis to coincide with changes in fuel costs.

●

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

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

●

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

●	TCA — The TCA provides for the recovery outside of rate cases of transmission plant revenue requirements and allows for a return on CWIP for transmission investments.

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers have agreed to pay the full cost of renewable energy purchase and generation costs through a fuel clause and in exchange receive renewable energy credits associated with those resources.

PBRP and QSP Requirements — PSCo currently operates under an electric PBRP. This regulatory plan includes 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 2012. 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 2011, assuming normal weather, is listed below.


System Peak Demand (in MW)
2008		2009		2010		2011 Forecast
	6,903		6,258		6,401		6,521

The peak demand for PSCo’s system typically occurs in the summer. The 2010 uninterrupted system peak demand for PSCo occurred on July 14, 2010.

Energy Sources and Related Transmission Initiatives

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

Index

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

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

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

Resource Plan — In October 2009, the CPUC approved PSCo’s acquisitions of the resource plan filed which includes 900 MW of additional intermittent renewable energy resources (wind and PV solar) and approximately 280 MW of “new technology” renewable energy sources. The CPUC also approved the selection of approximately 900 MW of traditional gas-fired resources.

Gas-fired Resources

In October 2010, the CPUC approved the acquisition of approximately 900 MW of gas-fired generation from subsidiaries of Calpine Corporation and the cost recovery settlement. In its approval, the CPUC required PSCo to file a rate case by April 30, 2012 to move the investment into rate base. The revenue requirements associated with the asset acquisition will continue to be recovered through the PCCA until final rates are implemented. The PCCA went into effect on Jan. 1, 2011. Fuel costs will continue to flow through the ECA. The acquisition closed on Dec. 6, 2010, and the related PPAs for the Blue Spruce Energy Center and Rocky Mountain Energy Center were terminated effective that date. See Note 18 to the consolidated financial statements for further discussion.

Solar Resources

In 2010, PSCo filed an amendment to the approved resource plan to reduce the amount of solar resources (combination of PV solar and new technology renewable energy resources) to 60 MW and to seek new bids for 200 MW of wind power due to the combination of the transmission line delay and changed market circumstances. The matter has been referred to an ALJ with direction to resolve the matter by May 2011.

RES — In March 2010, Colorado enacted a law that increases the RES and now mandates that at least 30 percent of energy sales to be supplied by renewable energy for PSCo and removes the solar standard and replaces it with a distributed generation standard. Within the distributed generation standard, at least one-half of the distributed generation must be retail distributed generation, i.e., generation that is on customer premises behind the customer meter. The law requires that PSCo generate or cause to be generated electricity from renewable resources equaling:

●

At least 12 percent of its retail sales for the years 2011 through 2014;

●

At least 20 percent of its retail sales for the years 2015 through 2019; and

●

At least 30 percent of its retail sales for the years 2020 and thereafter.

In addition, distributed generation must equal:

●

At least 1 percent of retail sales in the years 2011 and 2012 and 1.25 percent of retail sales in the years 2013 and 2014;

●

At least 1.75 percent of retail sales in the years 2015 and 2016 and 2 percent of retail sales in the years 2017, 2018 and 2019; and

●

At least 3 percent of retail sales in the years 2020 and thereafter.

The CPUC has discretion to review the reasonableness of the increase in the distributed generation percentage in 2014. PSCo believes that its forecasted plan acquisitions of renewable resources only need minor modification to comply with the new standard.

CACJA — The CACJA was signed into law in April 2010. The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal-fired generation identified in the plan. The plan was required to consider both current and reasonably foreseeable CAA requirements and allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Dec. 31, 2017. The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval. The CACJA permits the CPUC to consider interim rate increases after Jan. 1, 2012, while the rate filing is pending and allows for multi-year rate plans.

Index

In December 2010, the CPUC approved the following:

●

Shutdown Cherokee Units 1 and 2 in 2011 and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

●

Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

●

Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (352 MW) in 2013 to natural gas;

●

Shutdown Valmont Unit 5 (186 MW) in 2017;

●

Install SCR for controlling NOx and a scrubber for controlling SO2 on Pawnee Station in 2014;

●

Install SCR on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

●

Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

The CPUC provided for recovery on CWIP in rate base in each rate case and deferred accounting of accelerated depreciation costs. PSCo needs to make applications for detailed cost review before commencing each phase of the plan. The CPUC also encouraged PSCo to hold stakeholder meetings to discuss issues around a multi-year rate plan. In January 2011, the AQCC unanimously approved incorporation of the CACJA plan into Colorado’s regional haze SIP. See Note 13 to the consolidated financial statements for further discussion. The Colorado state legislature must approve the SIP, which will contain provisions of the CACJA approved by the CPUC. Unless changed by the legislature during its review process, the SIP (including the CACJA plan) will be sent to the EPA for incorporation into federal CAA regulations. The total investment associated with the adopted plan is approximately $1.0 billion over the next seven years. The rate impact of the proposed plan is expected to increase future bills on average by 2 percent annually.

San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a project for 230 KV and 345 KV line and substation construction. The line is intended to assist in bringing solar power in the San Luis Valley to load. The line was originally expected to be placed in-service in 2013; however, that appears unlikely now due to delays in the siting and permitting of the line. Several landowners oppose this transmission line, including two large ranches. In November 2010, the ALJ issued a recommended decision granting the CPCN but proposing a significant refund obligation if the line was not heavily utilized ten years after it was in service. Several parties, including PSCo, filed exceptions to the recommended decision. The CPUC deliberated on the exceptions to the recommended decision and granted the CPCN without the refund obligation recommended by the ALJ. A written decision will follow.

SmartGridCity™ CPCN — As part of the PSCo electric rate case, the CPUC included recovery of the revenue requirements associated with the $45 million of capital and $4 million O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base. The CPUC seeks additional information regarding the future plans to utilize SmartGridCity™ in an application to recover the additional capital. PSCo believes that it will be able to satisfy that requirement.

Fuel Supply and Costs

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

											Weighted
	Coal					Natural Gas					Average
	Cost		Percent			Cost		Percent			Fuel Cost
2010	$	1.58		85	%	$	5.05		15	%	$	2.11
2009		1.52		82			3.99		18			1.97
2008		1.42		84			7.03		16			2.31

See Item 1A for further discussion.

Index

Fuel Sources

Coal — Coal inventory levels may vary widely among plants. However, PSCo normally maintains approximately 41 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2010 and 2009 were approximately 34 and 68 days usage, respectively, based on the maximum burn rate for all of PSCo’s coal-fired plants. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2010 and 2009, PSCo’s coal requirements for existing plants were approximately 11.2 million and 9.2 million tons, respectively.

PSCo has contracted for coal suppliers to supply 84 percent of its coal requirements in 2011, 53 percent of its coal requirements in 2012 and 22 percent of its coal requirements in 2013. Any remaining requirements will be filled through an RFP process or through over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2011, 67 percent of its coal requirements in 2012 and 66 percent of its coal requirements in 2013. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather, and availability of equipment.

Natural gas — PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. The supply contracts expire in various years from 2011 through 2021. The transportation and storage contracts expire in various years from 2011 to 2040. The majority of natural gas supply contracts have pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 10 to the consolidated financial statements for further discussion. Most transportation contract pricing is based on FERC approved transportation tariff rates. These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers. 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, 2010, PSCo’s commitments related to supply contracts were approximately $817 million and transportation and storage contracts were approximately $1.0 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 Item 7A for further discussion.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices, and certain other activities of Xcel Energy’s utility subsidiaries, and enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of PSCo’s utility activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 12 to the consolidated financial statements for further discussion.

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FERC Penalty Guidelines Issued — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC. The guidelines establish a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation. Penalties range between a minimal amount and $72.5 million based on an application of a multiplier. The guidelines indicate that the FERC can deviate from the guidelines in its discretion. The guidelines can apply to any investigation where the FERC staff has not begun settlement negotiations regarding an alleged violation.

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

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

In 2008, PSCo was subject to an audit of its compliance with the NERC and regional reliability standards by the WECC, the NERC regional entity for the PSCo system. In October 2008, the WECC auditors issued their final audit report on PSCo’s compliance with certain NERC mandatory electric reliability standards. The report found a possible violation of one reliability standard related to relay maintenance.

In 2008, PSCo filed self-reports with the WECC relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain CIPS. In 2009, PSCo reached agreement with the WECC that would resolve the open 2008 audit finding and the 2008 self reports by payment of a non-material penalty. In February 2010, PSCo executed a definitive settlement agreement. This settlement agreement has been approved by the NERC and was filed for FERC approval in December 2010. In January 2011, the FERC issued an order accepting the NERC approval with no further action.

In March 2010, the WECC conducted a compliance spot check to evaluate compliance with the NERC CIPS. The regional entity issued a non-public final report in August 2010 alleging violations of certain CIPS requirements, including certain violations common to all Xcel Energy utility subsidiaries. Xcel Energy disputes the alleged violations and is working to resolve the issues. To what extent the regional entities or NERC may seek to impose penalties for violations of CIPS is unknown at this time.

In July 2010, the WECC issued a non-public NAV related to (1) two alleged non-common CIPS violations identified in the joint CIPS spot-check, and (2) two violations self-reported by PSCo 2010 related to certain BAL standards. The WECC NAV proposed a non-material penalty. PSCo requested that the proceedings be deferred to allow settlement negotiations to resolve the NAV. The matter is now in settlement discussions. Based on these discussions, a second self-report similar to one of the previously filed BAL self-reports was filed 2010, and this report will be resolved along with the other matters pending with WECC. None of the alleged or self-reported violations is expected to result in a material penalty.

In November 2010, PSCo filed self-reports with the WECC regarding potential violations of certain NERC CIPS. Additional self-reports of potential violations of CIPS were filed in January 2011. Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of their CIPS compliance programs. Whether and to what extent penalties may be assessed against PSCo for the issues identified and self-reported to date is unclear.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In October 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions. In December 2010, the NERC issued a revised advisory extending the period for affected entities to complete their initial assessment and corrective actions until 2013 and 2014, respectively. The advisory compliance cost for PSCo is estimated at $6.8 million. PSCo will seek recovery through applicable rate-making mechanisms.

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates. In 2009, PSCo filed a tariff to participate with other utilities in WestConnect, a consortium of utilities offering regionalized non-firm transmission services. The WestConnect tariff was effective in the first quarter of 2009. The WestConnect tariff has not had a material impact on PSCo transmission usage or revenues. WestConnect may provide wholesale energy market functions in the future, but would not be an RTO.

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Proposed Rulemaking on Transmission Planning and Cost Allocation — In June 2010, the FERC issued a NOPR regarding transmission planning and cost allocation. The NOPR would (1) require that local and regional transmission planning processes address public policy requirements established by state or federal laws or regulations; (2) improve coordination between neighboring transmission planning regions of interregional facilities; (3) eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory, referred to as a ROFR; and (4) require cost allocation methods for transmission facilities to satisfy newly established cost allocation principles. The FERC will consider the written comments provided on the NOPR prior to adopting a final rule. The content of the final rule cannot be predicted at this time; however, limiting an incumbent utility’s preferential ROFR to build transmission in its service territory states may have a negative impact on longer-term growth opportunities for the Xcel Energy utility subsidiaries.

Market-Based Rate Rules — Each of the Xcel Energy utility subsidiaries was granted market-based rate authority. PSCo filed a request for market-based rate reauthorization outside its service territory in June 2010. The request is pending FERC action. Presently the Xcel Energy utility subsidiaries may not sell power at market-based rates within the PSCo BAL, where they have been found to have market power under the FERC’s applicable analysis. PSCo has cost-based coordination tariffs that they may use to make sales in their balancing authorities.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of use of network transmission service arrangements 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, rules and approved tariffs that could result in material penalties under the FERC penalty guidelines. The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report. Xcel Energy provided a response that disagreed with the preliminary report and demonstrated compliance with applicable standards. In December 2010, the DOI initiated settlement negotiations with Xcel Energy regarding possible resolution of the non-public investigation. The final outcome of the FERC DOI investigation and to what extent FERC may seek to impose penalties for violations is unknown at this time.

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

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

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Electric Operating Statistics


	Year Ended Dec. 31,
	2010			2009			2008
Electric sales (Millions of KWh)
Residential		9,087			8,715			8,905
Commercial and industrial		18,984			18,448			19,137
Public authorities and other		227			226			229
Total retail		28,298			27,389			28,271
Sales for resale		7,079			6,949			7,756
Total energy sold		35,377			34,338			36,027

Number of customers at end of period
Residential		1,159,287			1,150,181			1,142,106
Commercial and industrial		152,671			151,637			150,826
Public authorities and other		56,837			58,371			58,195
Total retail		1,368,795			1,360,189			1,351,127
Wholesale		26			30			35
Total customers		1,368,821			1,360,219			1,351,162

Electric revenues (Thousands of Dollars)
Residential	$	1,013,188		$	862,242		$	914,531
Commercial and industrial		1,552,116			1,309,770			1,514,652
Public authorities and other		48,847			44,434			44,066
Total retail		2,614,151			2,216,446			2,473,249
Wholesale		368,396			349,909			457,623
Other electric revenues		72,498			112,223			52,057
Total electric revenues	$	3,055,045		$	2,678,578		$	2,982,929

KWh sales per retail customer		20,674			20,136			20,924
Revenue per retail customer	$	1,910		$	1,630		$	1,831
Residential revenue per KWh		11.15	¢		9.89	¢		10.27	¢
Commercial and industrial revenue per KWh		8.18			7.10			7.91
Wholesale revenue per KWh		5.20			5.04			5.90

NATURAL GAS UTILITY OPERATIONS

The most significant developments in the natural gas operations of PSCo are continued volatility in natural gas market prices, safety requirements for natural gas pipelines and the continued trend of declining use per residential customer, as well as small commercial and industrial customers (C&I), as a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 2000 to 2010, average annual sales to the typical PSCo residential customer declined from 93 MMBtu per year to 81 MMBtu per year, and to a typical small C&I customer declined from 455 MMBtu per year to 403 MMBtu per year on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

Public Utility Regulation

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

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

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

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

●	PDRA — The PDRA recovers revenue lost to decreasing use per customer beyond a threshold. No revenue is currently recovered through this clause.

PBRP and QSP Requirements — The CPUC established a combined electric and natural gas QSP. This regulatory plan includes 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 2012. 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.

See Note 12 to the consolidated financial statements for further discussion.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,908,006 MMBtu. In addition, firm transportation customers hold 562,175 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,470,181 MMBtu per day. The maximum daily deliveries for PSCo in 2010 for firm and interruptible services were 1,820,806 MMBtu on Jan. 7, 2010.

PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,838,824 MMBtu per day, which includes 849,568 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 41,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations and a small amount is received directly from wellhead sources.

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

Natural Gas Supply and Costs

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

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

2010	$	5.10
2009		5.13
2008		7.04

PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2010, PSCo was committed to approximately $1.1 billion in such obligations under these contracts, which expire in various years from 2011 through 2029.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2010, PSCo purchased natural gas from approximately 41 suppliers.

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Natural Gas Operating Statistics


	Year Ended Dec. 31,
	2010			2009			2008
Natural gas deliveries (Thousands of MMBtu)
Residential		95,231			95,566			96,871
Commercial and industrial		39,399			39,878			41,121
Total retail		134,630			135,444			137,992
Transportation and other		101,597			109,906			115,923
Total deliveries		236,227			245,350			253,915

Number of customers at end of period
Residential		1,200,950			1,193,418			1,186,255
Commercial and industrial		99,866			99,654			99,425
Total retail		1,300,816			1,293,072			1,285,680
Transportation and other		5,240			4,789			4,313
Total customers		1,306,056			1,297,861			1,289,993

Natural gas revenues (Thousands of Dollars)
Residential	$	736,160		$	745,728		$	941,077
Commercial and industrial		274,288			285,199			368,143
Total retail		1,010,448			1,030,927			1,309,220
Transportation and other		64,998			63,032			64,512
Total natural gas revenues	$	1,075,446		$	1,093,959		$	1,373,732

MMBtu sales per retail customer		103.50			104.75			107.33
Revenue per retail customer	$	777		$	797		$	1,018
Residential revenue per MMBtu		7.73	¢		7.80	¢		9.71	¢
Commercial and industrial revenue per MMBtu		6.96			7.15			8.95
Transportation and other revenue per MMBtu		0.64			0.57			0.56

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. See Note 13 to the consolidated financial statements for further discussion.

EMPLOYEES

The number of full-time PSCo employees at Dec. 31, 2010 and 2009 was 2,823 and 2,791, respectively. Of these full-time employees, 2,142, or 76 percent, and 2,124, or 76 percent, respectively, are covered under collective bargaining agreements which expire in May 2014. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to PSCo and are not considered in the above amounts.

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Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes PSCo, is to understand, manage and, when possible, mitigate material risk; management is responsible for identifying and managing risks, while Xcel Energy’s Board of Directors oversees and holds management accountable. As described more fully below, PSCo is faced with a number of different types of risk. We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and PSCo’s senior management. Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

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

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy’s and PSCo’s strategy. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management. At a threshold level, we have developed a robust compliance program and promote a culture of compliance, which mitigates risk. Building on this culture of compliance, we manage and mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services. While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

Management also communicates with Xcel Energy’s Board and key stakeholders regarding risk. Management provides information to Xcel Energy’s Board in presentations and communications over the course of the year. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and PSCo’s strategy. The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. The Xcel Energy Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Xcel Energy Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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Risks Associated with Our Business

Environmental Risks

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, 2010, these sites included:

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

●	Third party sites, such as landfills, for which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.

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

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

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

There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. 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.

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

Financial Risks

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

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

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

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. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity 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 issues and events throughout the world economy, such as the recent concerns regarding European sovereign debt. Capital market disruption events and resulting broad financial market distress, such as the events surrounding the collapse in the U.S. sub-prime mortgage market, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

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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 price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The recently enacted Dodd-Frank Wall Street Reform Act may require broad clearing of financial swap transactions through a central counterparty, which may lead to additional margin requirements that could impact our liquidity. Also, in October 2010, the FERC finalized its rulemaking addressing the credit policies of organized electric markets, such as MISO, which may lead to additional margin requirements that could impact our liquidity.

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

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

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Legislation related to health care could also significantly change our benefit programs and costs.

Operational Risks

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

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

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

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

There are inherent in our natural gas transmission and 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 natural gas transmission or distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks is greater.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events impacting the credit or liquidity of 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 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, 2010, Xcel Energy had approximately $9.3 billion of long-term debt and $0.5 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 for 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, 2010, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $155.7 million and $18.0 million of exposure. Xcel Energy also had additional guarantees of $32.5 million at Dec. 31, 2010 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund 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.

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

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

We have historically paid quarterly dividends to Xcel Energy. In 2010, 2009 and 2008 we paid $265.8 million, $266.2 million and $271.0 million of dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs. This could adversely affect our liquidity. The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress. Internationally, other nations have already agreed to regulate emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” by 2012. In addition, in 2009, the United States submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord. Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA. In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants in July 2011, with final standards to be issued in 2012.

We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 13, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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

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We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include, but are not limited to, rules associated with mercury, regional haze, ozone, ash management and cooling water intake systems. The costs of investment to comply with these rules could be substantial. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

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.

Macroeconomic Risks

Economic conditions could negatively impact our business.

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

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

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

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

The insurance industry has also been affected by these events and the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. For example, wildfire events, particularly in the geographic areas we serve, may cause insurance for wildfire losses to become difficult or expensive to obtain.

A security breach of our information systems could impact the reliability of the our generation, transmission and distribution systems and also subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to system operating information and information regarding our customers and employees. We are unable to quantify the potential impact of such an event, however, such an event could result in significant costs and penalties, as well as legal costs.

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

The degree to which we are able to maintain day-to-day operations in response to unforeseen events, potentially through the execution of our business continuity plans, will in part determine the financial impact of certain events on our financial condition and results. It’s difficult to predict the magnitude of such events and associated impacts.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, higher fuel costs could reduce customer demand and/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, 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.

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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

Electric Utility Generating Stations:

PSCo

Summer 2010

Net Dependable

Station, Location and Unit

Fuel

Installed

Capability (MW)

Steam:

Arapahoe-Denver, Colo., 2 Units

Coal

1951-1955

153

Cherokee-Denver, Colo., 4 Units

Coal

1957-1968

717

Comanche-Pueblo, Colo., 3 Units

Coal

1973-2010

1,171

(a)

Craig-Craig, Colo., 2 Units

Coal

1979-1980

(b)

Hayden-Hayden, Colo., 2 Units

Coal

1965-1976

237

(c)

Pawnee-Brush, Colo.

Coal

1981

505

Valmont-Boulder, Colo.

Coal

1964

184

Zuni-Denver, Colo., 2 Units

Coal

1948-1954

Combustion Turbine:

Blue Spruce-Aurora, Colo., 2 Units

Natural Gas

2003

278

(e)

Fort St. Vrain-Platteville, Colo., 6 Units

Natural Gas

1972-2009

969

Rocky Mountain-Keenesburg, Colo., 3 Units

Natural Gas

2004

601

(e)

Various locations, 6 Units

Natural Gas

Various

174

Hydro:

Cabin Creek-Georgetown, Colo.

Pumped Storage, 2 Units

Hydro

1967

210

Various locations, 9 Units

Hydro

Various

Wind:

Ponnequin-Weld County, Colo.

Wind

1999-2001

(d)

Diesel:

Cherokee-Denver, Colo., 2 Units

Diesel

1967

Total

5,404

(a)	Construction of Comanche Unit 3, a 750 MW coal-fired unit, was completed in 2010. PSCo owns two-thirds of the completed unit.

(b)	Based on PSCo’s ownership interest of 10 percent.

(c)	Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.

(d)	Amount represents nameplate rating capacity.

(e)	PSCo completed its acquisition of Blue Spruce Energy Center and Rocky Mountain Energy Center in December 2010. See Note 18 to the consolidated financial statements for further information.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2010:

Conductor Miles
345 KV			1,614
230 KV			11,519
138 KV			92
115 KV			4,882
Less than 115 KV			72,946

PSCo had 222 electric utility transmission and distribution substations at Dec. 31, 2010.

Natural gas utility mains at Dec. 31, 2010:


Miles
Transmission			2,301
Distribution			21,302

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Item 3 — Legal Proceedings

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

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 13 to the consolidated financial statements. For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation, Summary of Recent Federal Regulatory Developments and Note 12 to the consolidated financial statements.

Item 4 — Reserved

PART II

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

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

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

●	PSCo’s credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent. PSCo was in compliance as its equity-to-total capitalization ratio was 54 percent and 56 percent at Dec. 31, 2010 and 2009, respectively.

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

The dividends declared during 2010 and 2009 were as follows:

(Thousands of Dollars)	2010		2009
First quarter	$	66,655	$	66,816
Second quarter		66,729		65,960
Third quarter		66,600		65,995
Fourth quarter		66,828		65,822

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).

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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. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of PSCo to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies; and the other risk factors listed from time to time by PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2010 and Exhibit 99.01 to PSCo’s Form 10-K for the year ended Dec. 31, 2010.

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

Results of Operations

PSCo’s net income was approximately $399.7 million for 2010, compared with approximately $323.3 million for 2009.

Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas and coal used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin:

(Millions of Dollars)	2010			2009
Electric revenues	$	3,055		$	2,679
Electric fuel and purchased power		(1,513	)		(1,400	)
Electric margin	$	1,542		$	1,279

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

Electric Revenues
(Millions of Dollars)	2010 vs. 2009
Retail rate increase	$	155
Fuel and purchased power cost recovery		93
Renewable energy credit sales		33
Phase II and seasonal rates		31
DSM revenue and incentive (partially offset by expenses)		21
Estimated impact of weather		15
Trading		6
Transmission revenues		6
Retail sales increase (excluding weather impact)		6
Other, net		10
Total increase in electric revenues	$	376

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Electric Margin

(Millions of Dollars)	2010 vs. 2009
Retail rate increase	$	155
Phase II and seasonal rates		31
DSM revenue and incentive (partially offset by expenses)		21
Estimated impact of weather		15
Renewable energy credit sales		14
Firm wholesale		8
Retail sales increase (excluding weather impact)		6
Transmission revenues		6
Trading		(7	)
Other, net		14
Total increase in electric margin	$	263

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details the natural gas revenues and margin:


(Millions of Dollars)	2010			2009
Natural gas revenues	$	1,075		$	1,094
Cost of natural gas sold and transported		(685	)		(712	)
Natural gas margin	$	390		$	382

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

Natural Gas Revenues


(Millions of Dollars)	2010 vs. 2009
Purchased natural gas adjustment clause recovery	$	(27	)
Estimated impact of weather		(1	)
DSM revenue and incentive (partially offset by expenses)		7
Other, net		2
Total decrease in natural gas revenues	$	(19	)

Natural Gas Margin


(Millions of Dollars)	2010 vs. 2009
DSM revenue and incentive (partially offset by expenses)	$	7
Estimated impact of weather		(1	)
Other, net		2
Total increase in natural gas margin	$	8

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Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased by approximately $48.4 million, or 7.7 percent for 2010, compared to 2009. The following summarizes the components of the changes in O&M expenses for the year ended Dec. 31:


(Millions of Dollars)	2010 vs. 2009
Higher plant generation costs	$	20
Higher contract labor costs		11
Higher labor costs		7
Higher information technology costs		6
Higher material costs		4
Lower employee benefit costs		(6	)
Other, net		6
Total increase in operating and maintenance expenses	$	48

DSM Program Expenses — DSM program expenses increased by approximately $24.0 million for 2010, compared with 2009. The higher expense is attributable to the continued expansion of programs and regulatory commitments. PSCo has established DSM incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers. PSCo recovers DSM program expenses concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $28.1 million, or 11.0 percent, for 2010 compared with 2009. The increase was primarily due to Comanche Unit 3 going in service and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $7.7 million for 2010, compared with 2009. The increase is primarily due to an increase in property taxes.

Other Income, Net — Other income, net, increased by approximately $24.4 million for 2010, compared with 2009. The increase is primarily due to the COLI settlement in July 2010.

AFUDC — AFUDC decreased by approximately $42.9 million for 2010 compared with 2009. This decrease was primarily due to Comanche Unit 3 going into service and lower AFUDC rates, as well as lower interest rates.

Interest Charges — Interest charges increased by approximately $5.7 million, or 3.4 percent, for 2010 compared with 2009. The increase is primarily due to the issuance of long-term debt.

Income Taxes — Income tax expense increased by approximately $58.8 million for 2010, compared with 2009. The increase in income tax expense was primarily due to an increase in pretax income in 2010 and increased plant-related deductions in 2009 as well as one-time adjustments for a write-off of tax benefit previously recorded for Medicare Part D subsidies and an adjustment at PSRI related to the COLI Tax Court proceedings in 2010. This was partially offset by the non-taxability of the Provident settlement and increased state unitary tax benefit in 2010. See Note 7 to the consolidated financial statements for further discussion. The effective tax rate was 36.4 percent for 2010, compared with 34.5 percent for 2009. The higher effective tax rate for 2010 was primarily due to the adjustments referenced above.

The effective tax rate for 2010 differs from the statutory federal income tax rate, primarily due to state income tax expense and the adjustments referenced above. The effective tax rate for 2009 differs from the statutory federal income tax rate, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant-related regulatory differences. See Note 7 to the consolidated financial statements for further discussion.

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. See Note 10 to the consolidated financial statements for further discussion.

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

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 to the extent such exposure exists.

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

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


(Thousands of Dollars)	2010			2009
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	651		$	554
Contracts realized or settled during the period		3,811			(9,867	)
Commodity trading contract additions and changes during period		(2,645	)		9,964
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	1,817		$	651

At Dec. 31, 2010, 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
PSCo		1		572		1,245		—		—		1,817

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

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

At Dec. 31, 2010, a 10 percent increase or decrease in market prices over the next 12 months for commodity trading contracts would have no impact on pretax income from continuing operations.

PSCo’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:


	Year Ended
(Millions of Dollars)	Dec. 31		VaR Limit			Average		High		Low
2010	$	0.15		$	3.00	$	0.22	$	0.64	$	0.03
2009		0.50			5.00		0.44		2.02		0.06

Index

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

At Dec. 31, 2010, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $2.7 million annually. See Note 10 to the consolidated financial statements for further discussion.

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

At Dec. 31, 2010, a 10 percent increase in prices would have resulted in an increase in credit exposure of $76.2 million, while a decrease of 10 percent in prices would have resulted in a decrease in credit exposure of $10.9 million.

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

Fair Value Measurements

PSCo follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and generally requires that the most observable inputs available be used for fair value measurements. Note 10 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2010. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues as necessary. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for this credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2010.

Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of forwards and options that are either long-term in nature or related to certain commodities and delivery points with limited observability. Determining the fair value of these commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. There were no Level 3 commodity derivative assets or liabilities at Dec. 31, 2010.

Item 8 — Financial Statements and Supplementary Data

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

See Note 17 to the consolidated financial statements for summarized quarterly financial data.

Index

Management Report on Internal Controls Over Financial Reporting

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

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

PSCo management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2010, the company’s internal control over financial reporting is effective based on those criteria.

/S/ DAVID L. EVES		/S/ DAVID M. SPARBY
David L. Eves		David M. Sparby
President and Chief Executive Officer		Vice President and Chief Financial Officer
February 28, 2011		February 28, 2011

Index

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Public Service Company of Colorado

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 28, 2011

Index

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2010			2009			2008
Operating revenues
Electric	$	3,055,045		$	2,678,578		$	2,982,929
Natural gas		1,075,446			1,093,959			1,373,732
Steam and other		33,879			35,772			36,383
Total operating revenues		4,164,370			3,808,309			4,393,044

Operating expenses
Electric fuel and purchased power		1,513,334			1,399,541			1,818,772
Cost of natural gas sold and transported		685,210			712,079			994,221
Cost of sales — steam and other		16,995			15,426			15,507
Other operating and maintenance expenses		677,359			628,999			605,008
Demand side management program expenses		128,939			104,919			32,990
Depreciation and amortization		284,139			256,062			252,384
Taxes (other than income taxes)		103,342			95,612			84,597
Total operating expenses		3,409,318			3,212,638			3,803,479

Operating income		755,052			595,671			589,565

Other income, net		29,117			4,696			16,748
Allowance for funds used during construction — equity		11,370			41,118			36,158

Interest charges and financing costs
Interest charges — includes other financing costs of $5,649, $5,686, and $5,754, respectively		171,945			166,212			154,313
Allowance for funds used during construction — debt		(5,307	)		(18,452	)		(18,266	)
Total interest charges and financing costs		166,638			147,760			136,047

Income before income taxes		628,901			493,725			506,424
Income taxes		229,181			170,405			166,628
Net income	$	399,720		$	323,320		$	339,796

See Notes to Consolidated Financial Statements

Index

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2010			2009			2008
Operating activities
Net income	$	399,720		$	323,320		$	339,796
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		289,050			260,935			260,873
Demand side management program amortization		19,666			27,625			32,990
Deferred income taxes		154,861			197,348			85,875
Amortization of investment tax credits		(2,693	)		(2,375	)		(2,760	)
Allowance for equity funds used during construction		(11,370	)		(41,118	)		(36,158	)
Provision for bad debts		21,571			21,189			28,372
Net realized and unrealized hedging and derivative transactions		(23,112	)		42,896			(19,012	)
Changes in operating assets and liabilities:
Accounts receivable		16,807			7,082			(10,469	)
Accrued unbilled revenues		16,418			40,573			5,665
Inventories		34,424			(19,700	)		(24,028	)
Prepayments and other		14,328			(44,555	)		3,438
Accounts payable		(106,632	)		(32,982	)		(607	)
Net regulatory assets and liabilities		17,098			(64,251	)		74,944
Other current liabilities		16,067			(1,531	)		3,700
Pension and employee benefit obligation		(29,820	)		(216,696	)		(63,643	)
Change in other noncurrent assets		(2,578	)		375			436
Change in other noncurrent liabilities		(11,474	)		(24,796	)		15,900
Net cash provided by operating activities		812,331			473,339			695,312

Investing activities
Utility capital/construction expenditures		(571,746	)		(627,421	)		(809,738	)
Allowance for equity funds used during construction		11,370			41,118			36,158
Acquisition of generation assets		(732,495	)		—			—
Investments in utility money pool arrangement		(831,000	)		(274,200	)		(439,500	)
Repayments from utility money pool arrangement		831,000			274,200			540,100
Other investments		—			—			23,716
Net cash used in investing activities		(1,292,871	)		(586,303	)		(649,264	)

Financing activities
Proceeds from (repayment of) short-term borrowings — net		174,400			55,000			(231,007	)
Proceeds from issuance of long-term debt		395,313			394,570			592,389
Repayment of long-term debt, including reacquisition premiums		—			(200,000	)		(301,445	)
Borrowings under utility money pool arrangement		255,500			802,800			755,600
Repayments under utility money pool arrangement		(339,500	)		(759,800	)		(714,600	)
Capital contributions from parent		260,116			108,813			127,529
Dividends paid to parent		(265,806	)		(266,188	)		(270,966	)
Net cash provided by (used in) financing activities		480,023			135,195			(42,500	)

Net increase (decrease) in cash and cash equivalents		(517	)		22,231			3,548
Cash and cash equivalents at beginning of period		33,429			11,198			7,650
Cash and cash equivalents at end of period	$	32,912		$	33,429		$	11,198

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(156,906	)	$	(147,186	)	$	(131,098	)
Cash paid for income taxes, net		(63,999	)		(6,155	)		(90,187	)
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	$	96,359		$	13,332		$	16,379
Storage assets under capital lease		12,628			143,105			—

See Notes to Consolidated Financial Statements

Index

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31,
	2010		2009
Assets
Current assets
Cash and cash equivalents	$	32,912	$	33,429
Accounts receivable, net		305,469		330,279
Accounts receivable from affiliates		21,042		33,396
Accrued unbilled revenues		297,535		313,953
Regulatory assets		176,596		122,161
Inventories		223,058		253,648
Deferred income taxes		13,877		56,223
Derivative instruments		6,294		28,704
Prepayments and other		54,235		58,968
Total current assets		1,131,018		1,230,761

Property, plant and equipment, net		9,200,556		8,104,841

Other assets
Regulatory assets		824,205		730,307
Derivative instruments		18,035		104,664
Other		55,016		47,175
Total other assets		897,256		882,146
Total assets	$	11,228,830	$	10,217,748

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	6,970	$	3,964
Short-term debt		269,400		95,000
Borrowings under utility money pool arrangement		—		84,000
Accounts payable		382,380		422,276
Accounts payable to affiliates		28,270		40,758
Regulatory liabilities		50,018		80,464
Taxes accrued		94,321		80,303
Dividends payable to parent		66,828		65,822
Derivative instruments		29,047		18,285
Accrued interest		48,866		47,300
Other		100,984		67,692
Total current liabilities		1,077,084		1,005,864

Deferred credits and other liabilities
Deferred income taxes		1,539,583		1,421,386
Deferred investment tax credits		47,338		50,031
Regulatory liabilities		472,846		494,579
Pension and employee benefit obligations		303,946		257,881
Customer advances		244,345		271,171
Derivative instruments		43,220		49,587
Asset retirement obligations		72,687		65,160
Other		61,334		31,287
Total deferred credits and other liabilities		2,785,299		2,641,082

Commitments and contingent liabilities
Capitalization
Long-term debt		3,228,253		2,824,988
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares		—		—
Additional paid-in capital		3,255,586		2,995,470
Retained earnings		875,151		742,243
Accumulated other comprehensive income		7,457		8,101
Total common stockholder’s equity		4,138,194		3,745,814
Total liabilities and equity	$	11,228,830	$	10,217,748

See Notes to Consolidated Financial Statements

Index

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except share data)

	Common Stock Issued									Accumulated			Total
					Additional					Other			Common
					Paid In		Retained			Comprehensive			Stockholders’
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2007		100	$	—	$	2,759,128	$	614,267		$	12,447		$	3,385,842
Adoption of new accounting guidance for endorsement split-dollar life insurance, net of tax of $(391)								(617	)					(617	)
Net income								339,796						339,796
Net derivative instrument fair value changes during the period, net of tax of $(2,910)											(4,819	)		(4,819	)
Comprehensive income for 2008														334,977
Common dividends declared to parent								(269,930	)					(269,930	)
Contribution of capital by parent						127,529								127,529
Balance at Dec. 31, 2008		100	$	—	$	2,886,657	$	683,516		$	7,628		$	3,577,801
Net income								323,320						323,320
Net derivative instrument fair value changes during the period, net of tax of $298											473			473
Comprehensive income for 2009														323,793
Common dividends declared to parent								(264,593	)					(264,593	)
Contribution of capital by parent						108,813								108,813
Balance at Dec. 31, 2009		100	$	—	$	2,995,470	$	742,243		$	8,101		$	3,745,814
Net income								399,720						399,720
Net derivative instrument fair value changes during the period, net of tax of $(394)											(644	)		(644	)
Comprehensive income for 2010														399,076
Common dividends declared to parent								(266,812	)					(266,812	)
Contribution of capital by parent						260,116								260,116
Balance at Dec. 31, 2010		100	$	—	$	3,255,586	$	875,151		$	7,457		$	4,138,194

See Notes to Consolidated Financial Statements

Index

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)

	Dec. 31
	2010			2009
Long-Term Debt
First Mortgage Bonds, Series due:
Oct. 1, 2012, 7.875%	$	600,000		$	600,000
March 1, 2013, 4.875%		250,000			250,000
April 1, 2014, 5.5%		275,000			275,000
Sept. 1, 2017, 4.375% (a)		129,500			129,500
Aug. 1, 2018, 5.8%		300,000			300,000
Jan. 1, 2019, 5.1% (a)		48,750			48,750
June 1, 2019, 5.125%		400,000			400,000
Nov. 15, 2020, 3.2%		400,000			—
Sept. 1, 2037, 6.25%		350,000			350,000
Aug. 1, 2038, 6.5%		300,000			300,000
Capital lease obligations, through 2060, 11.2% — 13.6%		190,223			183,026
Unamortized debt		(8,250	)		(7,324	)
Total		3,235,223			2,828,952
Less current maturities		6,970			3,964
Total long-term debt	$	3,228,253		$	2,824,988

Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2010 and 2009	$	—		$	—
Additional paid-in capital		3,255,586			2,995,470
Retained earnings		875,151			742,243
Accumulated comprehensive income		7,457			8,101
Total common stockholder’s equity	$	4,138,194		$	3,745,814

(a) Pollution control financing

See Notes to Consolidated Financial Statements

Index

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 recognized. PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.

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

●	PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA for PSCo’s retail jurisdiction. The ECA allows for sharing of margins on short term energy sales and margins from the sale of SO2 allowances.

●

PSCo generally recovers all purchased capacity costs through the PCCA for the company’s retail jurisdiction. The PCCA mechanism is revised annually. In October 2010, the CPUC approved the acquisition of generation assets from subsidiaries of Calpine Corporation and the associated cost recovery of the purchase through the PCCA mechanism on an interim basis until PSCo’s next electric rate case on or before April 30, 2012.

●

PSCo’s rates include annual adjustments for the recovery of conservation and energy management program costs, as well as a financial incentive based on its performance in achieving established goals through the DSMCA. PSCo is allowed to recover certain costs associated with renewable energy resources through a specific retail rate rider. PSCo recovers costs associated with investment in transmission facilities made after December 2008 through the TCA 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 and commodity trading results include the impact of all margin-sharing mechanisms. See Note 10 to the consolidated financial statements for further discussion.

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

Index

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 the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.

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

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

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

Normal Purchases and Normal Sales — PSCo enters into contracts for the purchase and sale of commodities for use in their business operations. Derivatives and hedging accounting guidance 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 derivative accounting as normal purchases or normal sales.

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

See Note 10 to the consolidated financial statements for further discussion.

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. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. Upon regulatory approval of deferred accounting for accelerated depreciation expenses, property, plant and equipment that is to be early decommissioned is reclassified as plant to be retired.

Index

PSCo records depreciation expense related to its plant 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, was 2.5 percent, 2.6 percent and 2.7 percent, for the years ended Dec. 31, 2010, 2009 and 2008, respectively.

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

Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases the CPUC has approved a more current recovery of cost associated with large capital projects, resulting in a lower recognition of AFUDC. One such project is the recently completed Comanche Unit 3 steam generation plant. A current recovery of construction costs is provided for any transmission assets in CWIP at the end of each year through the TCA rider.

Leases — PSCo evaluates a variety of contracts for lease classification at inception, including purchased power agreements and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease.

Three PSCo contracts for the use of certain natural gas pipeline or storage facilities meet the capital lease criteria and are accounted for as capital leases. The assets acquired under these capital leases were initially recorded in property, plant and equipment 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.

Variable Interest Entities — Effective Jan. 1, 2010, PSCo adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

Under its purchased power agreements, PSCo purchases power from independent power producing entities that own natural gas fueled power plants. Through various mechanisms in certain purchased power agreements, PSCo incurs variable fuel costs, and consequently these mechanisms have been determined to create variable interests in the independent power producing entities. Certain independent power producing entities are therefore variable interest entities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

Environmental Costs — Environmental costs are recorded when it is probable PSCo is liable for the costs and the liability can be reasonably estimated. Costs are 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.

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

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

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

Index

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 resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 14 to the consolidated financial statements. See Note 7 to the consolidated financial statements for more information on income taxes.

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

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

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

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

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

Inventory — All inventory is recorded at average cost.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

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

●	Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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 treatment in the rate setting process.

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-offs are recorded. See Note 14 to the consolidated financial statements for further discussion.

Conservation Programs — PSCo has implemented programs to assist its retail customers in conserving energy and reducing peak demand on the electric and natural gas systems. These programs include, but are not limited to, commercial process efficiency and lighting updates, and rebates for participation in air conditioner interruption and energy-efficient appliances.

Index

The costs incurred for DSM programs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs. For incentive programs designed to allow recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within twenty four months following the end of the annual period in which they are earned.

PSCo’s DSM program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage PSCo’s achievement of energy conservation goals and compensate for related lost sales margin. PSCo recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Deferred Financing Costs — Other assets included deferred financing costs of approximately $18.3 million and $17.5 million, net of amortization, at Dec. 31, 2010 and 2009, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.

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

Guarantees — PSCo recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligations that have been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as PSCo is released from risk under the guarantee. See Note 11 to the consolidated financial statements for further discussion.

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

Renewable Energy Credits — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, 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 purchased as a result of meeting load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements. As a result of state regulatory orders, PSCo records the cost of future compliance requirements that are recoverable in future rates as regulatory assets.

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 emission allowances. The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to deferred income taxes, regulatory assets and regulatory liabilities in the consolidated balance sheet and consolidated statements of cash flows. These reclassifications did not have an impact on net income.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2010 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Index

2.	Accounting Pronouncements

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the ASC were effective for interim and annual periods beginning after Nov. 15, 2009. PSCo implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. See Note 13 to the consolidated financial statements for further discussion.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. PSCo implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements. See Note 10 to the consolidated financial statements for further discussion.

3.	Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	329,523		$	354,428
Less allowance for bad debts		(24,054	)		(24,149	)
	$	305,469		$	330,279
Inventories
Materials and supplies	$	51,615		$	45,809
Fuel		67,187			96,964
Natural gas		104,256			110,875
	$	223,058		$	253,648
Property, plant and equipment, net
Electric plant	$	9,003,103		$	7,448,911
Natural gas plant		2,284,212			2,133,116
Common and other property		757,059			731,511
Plant to be retired (a)		236,606			48,572
Construction work in progress		231,636			1,038,013
Total property, plant and equipment		12,512,616			11,400,123
Less accumulated depreciation		(3,312,060	)		(3,295,282	)
	$	9,200,556		$	8,104,841

(a)

In 2009, in accordance with the CPUC’s approval of PSCo’s 2007 Colorado resource plan and subsequent rate case decisions, PSCo agreed to early retire its Cameo Units 1 and 2, Arapahoe Units 3 and 4 and Zuni Units 1 and 2 facilities. In 2010, in response to the CACJA, the CPUC approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017. Amounts are presented net of accumulated depreciation. See Item 1 – Public Utility Regulation for further discussion.

4. Borrowings and Other Financing Instruments

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The holding company may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company.

Index

The following table presents the money pool borrowings for PSCo:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Money pool borrowings	$	—	$	84
Weighted average interest rate		N/A		0.36	%
Money pool borrowing limit	$	250	$	250

Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. The following table presents commercial paper outstanding for PSCo:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Commercial paper outstanding	$	269	$	95
Weighted average interest rate		0.42		0.35	%
Commercial paper borrowing limit	$	675	$	675

Credit Facilities — PSCo must have revolving credit facilities in place at least equal to the amount of its respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit agreements. All credit facility bank borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities as presented in the table below. At Dec. 31, 2010 and Dec. 31, 2009, there were no credit facility bank borrowings outstanding.

At Dec. 31, 2010, PSCo had the following committed credit facility in effect, in millions of dollars:

Credit
Facility		Drawn*		Available		Original Term	Maturity
$	675	$	275	$	400	Five year	December 2011

*Includes outstanding commercial paper and issued and outstanding letters of credit.

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

●

The credit facility has one financial covenant requiring that PSCo’s debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 46 percent and 45 percent at Dec. 31, 2010 and 2009, respectively. If PSCo does not comply with the covenant, an event of default may be declared and it not remedied, 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 Xcel Energy will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets of Xcel Energy on a consolidated basis, 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 applicable debt ratings; this is 25 points.

●	The commitment fees, also based on long-term credit ratings, are calculated for the unused portion of the credit facility at 6 basis points for PSCo.

●

At Dec. 31, 2010, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $269.4 million of commercial paper outstanding and $4.7 million of letters of credit. At Dec. 31, 2009, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $95.0 million of commercial paper outstanding and $4.6 million of letters of credit.

●

Xcel Energy plans to syndicate new credit agreements at the Holding Company, NSP-Minnesota, PSCo, SPS and NSP-Wisconsin during the first quarter of 2011 to replace the existing agreements. The total anticipated size of the new credit facilities will be approximately $2.45 billion, of which $700 million is related to PSCo.

Index

Long-Term Borrowings

In November 2010, PSCo issued $400 million of 3.2 percent first mortgage bonds, due Nov. 15, 2020. PSCo used the proceeds to fund a portion of the $739 million purchase price of the Rocky Mountain Energy Center and the Blue Spruce Energy Center generation assets. PSCo funded the balance of the purchase price of these generation assets through short-term borrowings, and a capital contribution from Xcel Energy. See Note 18 to the consolidated financial statements for further discussion.

In June 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds, due June 1, 2019. PSCo added the proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the net proceeds to fund the payment at maturity of $200 million of 6.875 percent unsecured senior notes due July 15, 2009.

Maturities of long-term debt are:

(Millions of Dollars)
2011	$	7
2012		606
2013		257
2014		282
2015		6

5. Preferred Stock

PSCo has authorized the issuance of preferred stock.

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

6. Joint Ownership of Generation, Transmission and Gas Facilities

Following are the investments by PSCo in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2010:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Electric Generation:
Hayden Unit 1	$	89,176	$	59,191	$	—		75.5
Hayden Unit 2		82,079		54,680		21,405		37.4
Hayden Common Facilities		33,553		13,286		170		53.1
Craig Units 1 and 2		53,878		32,344		284		9.7
Craig Common Facilities 1, 2 and 3		33,710		15,444		2,534		6.5 - 9.7
Comanche Unit 3		882,626		11,069		130		66.7
Comanche Common Facilities		4,246		80		3,205		82.0
Electric Transmission:
Transmission and other facilities, including substations		148,002		55,249		2,080	Various
Gas Transportation:
Rifle to Avon		16,278		6,369		4		60.0
Total	$	1,343,548	$	247,712	$	29,812

Index

PSCo’s current operational assets include approximately 820 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 the issuance of its own securities to finance its portion of the construction costs. PSCo began major construction on a new jointly owned 750 MW, coal-fired unit in Pueblo, Colo. in January 2006. The new unit, Comanche Unit 3, was completed and commercial operations occurred in July 2010. PSCo is the operating agent under the joint ownership agreement. PSCo’s ownership interest in Comanche Unit 3 is 66.7 percent, and interest in the common facilities (assets used by all three Comanche units) is approximately 82 percent.

7. Income Taxes

COLI — In 2007, Xcel Energy and the U.S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. Xcel Energy paid the U.S. government a total of $64.4 million in settlement of the U.S. government’s claims for tax, penalty, and interest for tax years 1993 through 2007. Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court was dismissed and the Tax Court proceedings were dismissed in December 2010 and January 2011.

As part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the IRS reached an agreement in principle after a comprehensive financial reconciliation of Xcel Energy’s statement of account, dating back to tax year 1993. Upon completion of this review, PSRI recorded a net non-recurring tax and interest charge of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), during the first quarter of 2010. During the third quarter of 2010, Xcel Energy and the IRS came to final agreement on the applicable interest netting computations related to these tax years. Accordingly, PSRI recorded a reduction to expense of $0.6 million, net of tax, during the third quarter of 2010.

In July 2010, Xcel Energy, PSCo and PSRI entered into a settlement agreement with Provident Life & Accident Insurance Company (Provident) related to all claims asserted by Xcel Energy, PSCo and PSRI against Provident in a lawsuit associated with the discontinued COLI program. Under the terms of the settlement, Xcel Energy, PSCo and PSRI were paid $25 million by Provident and Reassure America Life Insurance Company in the third quarter of 2010. The $25 million proceeds were not subject to income taxes.

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, PSCo is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

As a result, PSCo expensed approximately $9.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. PSCo does not expect the $9.9 million of additional tax expense to recur in future periods.

Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Dec. 31, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2010, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. As of Dec. 31, 2010, there were no state income tax audits in progress.

Unrecognized Tax Benefits —The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions 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 ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

Index

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	1.3	$	1.0
Unrecognized tax benefit - Temporary tax positions		10.3		6.2
Unrecognized tax benefit balance	$	11.6	$	7.2

A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2010			2009			2008
Balance at Jan. 1	$	7.2		$	10.3		$	8.8
Additions based on tax positions related to the current year		4.1			3.7			2.9
Reductions based on tax positions related to the current year		(0.2	)		(0.3	)		(0.5	)
Additions for tax positions of prior years		1.6			2.2			2.0
Reductions for tax positions of prior years		(1.1	)		(0.5	)		(0.2	)
Settlements with taxing authorities		—			(8.2	)		—
Lapse of applicable statutes of limitations		—			—			(2.7	)
Balance at Dec. 31	$	11.6		$	7.2		$	10.3

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:

(Millions of Dollars)		Dec. 31, 2010				Dec. 31, 2009
NOL and tax credit carryforwards		$	(7.2	)		$	(4.0	)

The increase in the unrecognized tax benefit balance of $4.4 million in 2010 was due to the addition of similar uncertain tax positions related to current and prior years’ activity, partially offset by a decrease due to recently provided guidance pertaining to plant-related uncertain tax positions. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2010			2009			2008
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.1	)	$	(0.4	)	$	(3.8	)
Interest income related to unrecognized tax benefits		—			0.3			3.4
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.1	)	$	(0.1	)	$	(0.4	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2010, 2009 or 2008. During 2008, a $1.0 million liability for penalties accrued as of Dec. 31, 2007 was reversed.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2010		2009
Federal NOL carryforward	$	150.5	$	158.8
Federal tax credit carryforwards		14.6		13.6
State NOL carryforward		298.2		97.5
State tax credit carryforwards, net of federal detriment		8.4		7.1

The federal carryforward periods expire between 2021 and 2030. The state carryforward periods expire between 2011 and 2030.

Index

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

	2010			2009			2008
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		1.1			3.3			1.7
Regulatory differences — utility plant items		(0.5	)		(2.7	)		(2.2	)
Life insurance policies		(1.4	)		—			(0.2	)
Tax credits recognized, net of federal income tax expense		(0.8	)		(1.0	)		(1.1	)
Resolution of income tax audits and other		1.2			0.1			0.3
Change in unrecognized tax benefits		—			(0.1	)		(0.3	)
Previously recognized Medicare Part D subsidies		1.6			—			—
Other, net		0.2			(0.1	)		(0.3	)
Effective income tax rate		36.4	%		34.5	%		32.9	%

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

(Thousands of Dollars)	2010			2009			2008
Current federal tax expense (benefit)	$	76,228		$	(20,867	)	$	77,865
Current state tax expense (benefit)		(461	)		(2,327	)		6,219
Current change in unrecognized tax expense (benefit)		1,246			(1,374	)		(571	)
Deferred federal tax expense		147,704			172,454			81,326
Deferred state tax expense		11,180			27,508			8,859
Deferred change in unrecognized tax expense (benefit)		(920	)		864			(841	)
Deferred tax credits		(3,103	)		(3,478	)		(3,469	)
Deferred investment tax credits		(2,693	)		(2,375	)		(2,760	)
Total income tax expense	$	229,181		$	170,405		$	166,628

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

(Thousands of Dollars)	2010			2009			2008
Deferred tax expense excluding items below	$	160,543		$	224,484		$	109,504
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(6,075	)		(26,838	)		(26,540	)
Tax expense (benefit) allocated to other comprehensive income and other		393			(298	)		2,911
Deferred tax expense	$	154,861		$	197,348		$	85,875

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

(Thousands of Dollars)	2010		2009
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,527,296	$	1,352,421
Employee benefits		105,578		98,835
Other		122,856		123,676
Total deferred tax liabilities	$	1,755,730	$	1,574,932

Index

(Thousands of Dollars)	2010		2009
Deferred tax assets:
NOL carryforward	$	73,948	$	67,749
Unbilled revenue - fuel costs		59,182		59,318
Tax credit carryforward		22,983		20,737
Regulatory liabilities		18,249		20,371
Deferred investment tax credits		17,989		19,011
Litigation reserve		11,433		68
Other		26,240		22,514
Total deferred tax assets		230,024		209,768
Net deferred tax liability	$	1,525,706	$	1,365,164

8. 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. Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo. Consistent with the process for rate recovery of pension and postretirement benefits for its employees, PSCo accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy (multiple employer plans). PSCo is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, PSCo accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for PSCo employees.

Xcel Energy, which includes PSCo, offers various benefit plans to its employees. At Dec. 31, 2010, PSCo had 2,142 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.

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

The accounting guidance for fair value measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three Levels defined by the hierarchy and examples of each Level are as follows:

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

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

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

Pension Benefits

Xcel Energy, which includes PSCo, has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits. Xcel Energy’s and PSCo’s policy is to fully fund 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.

Index

Xcel Energy and PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the portfolio of pension investments is 9.72 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2010 were above the assumed level of 7.79 percent. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 were below the assumed level of 8.75 percent. Xcel Energy and PSCo continually review the pension assumptions. In 2011, Xcel Energy will use an investment-return assumption of 7.50 percent.

The assets are invested in a portfolio according to Xcel Energy’s and PSCo’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity; however, as we have experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for 2010 and 2009:

	2010			2009
Domestic and international equity securities		24	%		24	%
Long-duration fixed income securities		41			34
Short-to-intermediate term fixed income securities		11			19
Alternative investments		17			18
Cash		7			5
Total		100	%		100	%

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

Pension Plan Assets

The following tables present, for each of the fair value hierarchy Levels, pension plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010

(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	—	$	109,027		$	—	$	109,027
Short-term investments		122,643		26,683			—		149,326
Derivatives		—		8,140			—		8,140
Government securities		—		117,522			—		117,522
Corporate bonds		—		641,807			—		641,807
Asset-backed securities		—		—			26,986		26,986
Mortgage-backed securities		—		—			113,418		113,418
Common stock		117,899		—			—		117,899
Private equity investments		—		—			122,223		122,223
Commingled equity and bond funds		—		1,152,386			—		1,152,386
Real estate		—		—			73,701		73,701
Securities lending collateral obligation and other		—		(91,727	)		—		(91,727	)
Total	$	240,542	$	1,963,838		$	336,328	$	2,540,708

Index

	Dec. 31, 2009

(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	—	$	221,971		$	—	$	221,971
Short-term investments		—		324,683			—		324,683
Derivatives		—		11,606			—		11,606
Government securities		—		94,949			—		94,949
Corporate bonds		—		522,403			—		522,403
Asset-backed securities		—		—			47,825		50,232
Mortgage-backed securities		—		—			144,006		141,599
Common stock		89,260		—			—		89,260
Private equity investments		—		—			82,098		82,098
Commingled equity and bond funds		—		1,014,072			—		1,014,072
Real estate		—		—			66,704		66,704
Securities lending collateral obligation and other		—		(170,251	)		—		(170,251	)
Total	$	89,260	$	2,019,433		$	340,633	$	2,449,326

The following tables present the changes in Level 3 pension plan assets for the years ended Dec. 31, 2010 and 2009:


			Realized and			Purchases,
			Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Settlements, net			Dec. 31, 2010
Asset-backed securities	$	47,825	$	(3,678	)	$	(17,161	)	$	26,986
Mortgage-backed securities		144,006		(5,376	)		(25,212	)		113,418
Real estate		66,704		7,100			(103	)		73,701
Private equity investments		82,098		(1,032	)		41,157			122,223
Total	$	340,633	$	(2,986	)	$	(1,319	)	$	336,328

			Realized and			Purchases,
			Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)			Settlements, net			Dec. 31, 2009
Asset-backed securities	$	77,398	$	48,285		$	(77,858	)	$	47,825
Mortgage-backed securities		166,610		103,470			(126,074	)		144,006
Real estate		109,289		(43,207	)		622			66,704
Private equity investments		81,034		(5,682	)		6,746			82,098
Total	$	434,331	$	102,866		$	(196,564	)	$	340,633

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)	2010			2009
Accumulated Benefit Obligation at Dec. 31	$	2,865,845		$	2,676,174

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,829,631		$	2,598,032
Service cost		73,147			65,461
Interest cost		165,010			169,790
Plan amendments		18,739			(35,341	)
Actuarial loss		169,203			223,122
Benefit payments		(225,438	)		(191,433	)
Obligation at Dec. 31	$	3,030,292		$	2,829,631

Index

(Thousands of Dollars)	2010			2009
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	2,449,326		$	2,185,203
Actual return on plan assets		282,688			255,556
Employer contributions		34,132			200,000
Benefit payments		(225,438	)		(191,433	)
Fair value of plan assets at Dec. 31	$	2,540,708		$	2,449,326
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(489,584	)	$	(380,305	)

PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	464,143		$	447,815
Prior service credit		(22,414	)		(22,221	)
Total	$	441,729		$	425,594
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	441,729		$	425,594
PSCo accrued benefit liability recorded		122,336			90,989
Measurement Date	Dec. 31, 2010			Dec. 31, 2009
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Expected average long-term increase in compensation level		4.00			4.00
Mortality table	RP 2000			RP 2000

(a) Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheet.

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 2008 through 2010 for Xcel Energy’s pension plans and are not expected to require cash funding in 2011.

Xcel Energy made total pension contributions of $34 million and $200 million during 2010 and 2009, respectively.

●

Voluntary contributions were made to the Xcel Energy Pension Plan of $34 million in 2010.

●

Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009.

●

Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009.

●

Voluntary contributions were made across three of Xcel Energy’s pension plans for $134 million in January 2011. The contribution raised the overall funded status from 84 percent at Dec. 31, 2010 to 88 percent with all other pension assumptions remaining constant.

●

Pension funding contributions for 2012, 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 $175 million.

Plan Amendments — The 2010 increase of the projected benefit obligation for plan amendments is due to a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan.

Index

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


(Thousands of Dollars)	2010			2009			2008
Service cost	$	73,147		$	65,461		$	62,698
Interest cost		165,010			169,790			167,881
Expected return on plan assets		(232,318	)		(256,538	)		(274,338	)
Amortization of prior service cost		20,657			24,618			20,584
Amortization of net loss		48,315			12,455			11,156
Net periodic pension cost (credit)	$	74,811		$	15,786		$	(12,019	)
PSCo:
Net periodic pension cost	$	15,303		$	13,847		$	11,120
Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		7.79			8.50			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 2011 pension cost calculations will be 7.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including PSCo, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

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

Defined Contribution Plans

Xcel Energy, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo were approximately $8.4 million in 2010, $6.4 million in 2009 and $6.1 million in 2008.

Postretirement Health Care Benefits

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

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

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

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

Index

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

The following tables present, for each of the fair value hierarchy Levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010

(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	72,573	$	76,352	$	—	$	148,925
Derivatives		—		13,632		—		13,632
Government securities		—		3,402		—		3,402
Corporate bonds		—		70,752		—		70,752
Asset-backed securities		—		—		2,585		2,585
Mortgage-backed securities		—		—		19,212		19,212
Preferred stock		—		507		—		507
Commingled equity and bond funds		—		102,962		—		102,962
Securities lending collateral obligation and other		—		70,253		—		70,253
Total	$	72,573	$	337,860	$	21,797	$	432,230

	Dec. 31, 2009

(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	165,291	$	—	$	165,291
Short-term investments		—		2,226		—		2,226
Derivatives		—		5,937		—		5,937
Government securities		—		1,538		—		1,538
Corporate bonds		—		60,416		—		60,416
Asset-backed securities		—		—		8,293		8,372
Mortgage-backed securities		—		—		47,078		46,999
Preferred stock		—		540		—		540
Commingled equity and bond funds		—		89,296		—		89,296
Securities lending collateral obligation and other		—		4,074		—		4,074
Total	$	—	$	329,318	$	55,371	$	384,689

The following tables present the changes in Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2010 and 2009:

(Thousands of Dollars)	Jan. 1, 2010		Realized and Unrealized Gains		Purchases, Issuances, and Settlements, net			Dec. 31, 2010
Asset-backed securities	$	8,293	$	1,814	$	(7,522	)	$	2,585
Mortgage-backed securities		47,078		14,715		(42,581	)		19,212

(Thousands of Dollars)	Jan. 1, 2009		Realized and Unrealized Gains		Purchases, Issuances, and Settlements, net			Dec. 31, 2009
Asset-backed securities	$	8,705	$	1,029	$	(1,441	)	$	8,293
Mortgage-backed securities		69,988		3,022		(25,932	)		47,078

Index

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

(Thousands of Dollars)	2010			2009
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	728,902		$	794,597
Service cost		4,006			4,665
Interest cost		42,780			50,412
Medicare subsidy reimbursements		5,423			3,226
Amendments		—			(27,407	)
Plan participants’ contributions		14,315			13,786
Actuarial loss (gain)		68,126			(47,446	)
Benefit payments		(68,647	)		(62,931	)
Obligation at Dec. 31	$	794,905		$	728,902
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	384,689		$	299,566
Actual return on plan assets		53,430			72,101
Plan participants’ contributions		14,315			13,786
Employer contributions		48,443			62,167
Benefit payments		(68,647	)		(62,931	)
Fair value of plan assets at Dec. 31	$	432,230		$	384,689
Funded Status at Dec. 31:
Funded status	$	(362,675	)	$	(344,213	)
Current liabilities		(5,392	)		(2,240	)
Noncurrent liabilities		(357,283	)		(341,973	)
Net postretirement amounts recognized on consolidated balance sheets	$	(362,675	)	$	(344,213	)
PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	141,944		$	110,766
Prior service credit		(22,349	)		(25,262	)
Transition obligation		22,793			33,797
Total	$	142,388		$	119,301

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	142,388		$	119,301
PSCo accrued benefit liability recorded		165,653			148,022
Measurement Date	Dec. 31, 2010			Dec. 31, 2009

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - initial		6.50	%		6.80	%

Effective Dec. 31, 2010, the ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached increased from three years to eight 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.

Index

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

	One Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	98,812	$	(76,175	)
Service and interest components		5,006		(4,193	)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes PSCo, contributed $48.4 million during 2010 and $62.2 million in 2009 and expects to contribute approximately $40.5 million during 2011.

Plan Amendments — No amendments occurred during 2010 to the Xcel Energy health and welfare benefit plan.

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


(Thousands of Dollars)	2010			2009			2008
Service cost	$	4,006		$	4,665		$	5,350
Interest cost		42,780			50,412			51,047
Expected return on plan assets		(28,529	)		(22,775	)		(31,851	)
Amortization of transition obligation		14,444			14,444			14,577
Amortization of prior service cost		(4,932	)		(2,726	)		(2,175	)
Amortization of net loss		11,643			19,329			11,498
Net periodic postretirement benefit cost		39,412			63,349			48,446
PSCo:
Net periodic postretirement benefit cost recognized		22,306			40,277			26,989
Additional cost recognized due to effects of regulation		3,891			3,891			3,891
Net benefit cost recognized for financial reporting	$	26,197		$	44,168		$	30,880
Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term rate of return on assets (before tax)		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:


(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2011	$	254,426	$	59,752	$	4,770	$	54,982
2012		247,156		60,230		5,126		55,104
2013		249,908		60,607		5,475		55,132
2014		257,886		61,833		5,773		56,060
2015		259,978		63,184		6,061		57,123
2016-2020		1,338,658		325,154		34,115		291,039

Index

9. Other Income, Net

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


(Thousands of Dollars)	2010			2009			2008
Interest income	$	3,296		$	3,247		$	10,283
COLI settlement (See Note 7)		25,000			—			—
Other nonoperating income		1,758			3,192			2,954
Insurance policy (expenses) income		(937	)		(1,348	)		3,515
Other nonoperating expenses		—			(395	)		(4	)
Other income, net	$	29,117		$	4,696		$	16,748

10. Derivative Instruments and Fair Value Measurements

PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

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 its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

At Dec. 31, 2010, accumulated OCI related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

At Dec. 31, 2010, PSCo had vehicle fuel contracts designated as cash flow hedges extending through December 2014. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2010 and 2009.

At Dec. 31, 2010, accumulated OCI related to vehicle fuel cash flow hedges included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of any amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards at Dec. 31, 2010 and Dec. 31, 2009:


(Amounts in Thousands) (a)	Dec. 31, 2010		Dec. 31, 2009
Megawatt hours (MWh) of electricity		2,418		3,559
MMBtu of natural gas		59,465		45,352
Gallons of vehicle fuel		360		1,559

(a) Amounts are not reflective of net positions in the underlying commodities.

Index

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

(Thousands of Dollars)	2010			2009		2008
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	8,101		$	7,628	$	12,447
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(63	)		315		(3,294	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(581	)		158		(1,525	)
Accumulated other comprehensive income related to cash flow hedges at Dec. 31	$	7,457		$	8,101	$	7,628

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2010 and Dec. 31, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

The following table details the impact of derivative activity during the years ended Dec. 31, 2010 and 2009, on OCI, regulatory assets and liabilities and income:


	Dec. 31, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Losses			Regulatory Assets and Liabilities			Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(2,336	)(a)	$	—		$	—
Vehicle fuel and other commodity		(101	)		—			1,399	(c)		—			—
Total	$	(101	)	$	—		$	(937	)	$	—		$	—

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	(1,058	)(b)
Natural gas commodity		—			(83,295	)		—			40,862	(d)		—
Other		—			—			—			—			135	(b)
Total	$	—		$	(83,295	)	$	—		$	40,862		$	(923	)

Index

	Dec. 31, 2009
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains (Losses) Recognized During the Period in Income
(Thousands of Dollars)	Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities			Other Comprehensive Income (Losses)			Regulatory Assets and Liabilities
Derivatives designated as cash flow hedges
Interest rate	$	(632	)	$	—		$	(2,361	)(a)	$	—		$	—
Natural gas commodity		—			(14,641	)		—			66,311	(d)		(22,243	)(d)
Vehicle fuel and other commodity		1,140			—			2,624	(c)		—			—
Total	$	508		$	(14,641	)	$	263		$	66,311		$	(22,243	)
Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	2,009	(b)
Natural gas commodity		—			3,880			—			8,190	(d)		—
Total	$	—		$	3,880		$	—		$	8,190		$	2,009

(a)	Recorded to interest charges
(b)	Recorded to electric operating revenues. Portions of these total gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)	Recorded to other O&M expenses.
(d)	Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.

Credit Related Contingent Features — Contract provisions of PSCo’s derivative instruments may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit ratings. If the credit ratings were downgraded below investment grade, contracts underlying $5.6 million and $0.6 million of derivative instruments in a liability position at Dec. 31, 2010 and Dec. 31, 2009, respectively, would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $9.8 million and $3.4 million, respectively. At Dec. 31, 2010 and Dec. 31, 2009, there was no collateral posted on these specific contracts.

Certain of PSCo’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2010 and Dec. 31, 2009, PSCo had no collateral posted related to adequate assurance clauses in derivative contracts.

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three Levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting 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 reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing 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 valued with models requiring significant management judgment or estimation.

Index

Recurring Fair Value Measurements

The following table presents, for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	56	$	—	$	56	$	—		$	56
Other derivative instruments:
Trading commodity		—		5,765		—		5,765		(2,633	)		3,132
Natural gas commodity		—		1,396		—		1,396		(1,019	)		377
Total current derivative assets	$	—	$	7,217	$	—	$	7,217	$	(3,652	)		3,565
Purchased power agreements (a)													2,729
Current derivative instruments												$	6,294
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	68	$	—	$	68	$	—		$	68
Other derivative instruments:
Trading commodity		—		6,770		—		6,770		(2,118	)		4,652
Natural gas commodity		—		1,111		—		1,111		(211	)		900
Total noncurrent derivative assets	$	—	$	7,949	$	—	$	7,949	$	(2,329	)		5,620
Purchased power agreements (a)													12,415
Noncurrent derivative instruments												$	18,035

Current derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	5,192	$	—	$	5,192	$	(2,669	)	$	2,523
Natural gas commodity		—		41,753		—		41,753		(20,969	)		20,784
Total current derivative liabilities	$	—	$	46,945	$	—	$	46,945	$	(23,638	)		23,307
Purchased power agreements (a)													5,740
Current derivative instruments												$	29,047
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	5,526	$	—	$	5,526	$	(2,118	)	$	3,408
Natural gas commodity		—		350		—		350		(211	)		139
Total noncurrent derivative liabilities	$	—	$	5,876	$	—	$	5,876	$	(2,329	)		3,547
Purchased power agreements (a)													39,673
Noncurrent derivative instruments												$	43,220

(a)

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

(b)

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

Index

PSCo recognizes transfers between Levels as of the beginning of each period. The following table presents the transfers that occurred between Levels during the year ended Dec. 31, 2010.


	From Level 3
(Thousands of Dollars)	to Level 2
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	1,888
Noncurrent assets		4,988
Current liabilities		(1,265	)
Noncurrent liabilities		(3,724	)
Total	$	1,887

There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010. The transfer of amounts from Level 3 to Level 2 is due to the valuation of certain long term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

The following table presents for each of the hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:


	Dec. 31, 2009
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Other derivative instruments:
Trading commodity	$	—	$	2,380	$	986	$	3,366	$	(2,120	)	$	1,246
Natural gas commodity		—		8,752		—		8,752		111			8,863
Total current derivative assets	$	—	$	11,132	$	986	$	12,118	$	(2,009	)		10,109
Purchased power agreements (a)													18,595
Current derivative instruments												$	28,704
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	69	$	—	$	69	$	—		$	69
Other derivative instruments:
Trading commodity		—		1,514		1,535		3,049		677			3,726
Natural gas commodity		—		476		—		476		248			724
Total noncurrent derivative assets	$	—	$	2,059	$	1,535	$	3,594	$	925			4,519
Purchased power agreements (a)													100,145
Noncurrent derivative instruments												$	104,664

Index

	Dec. 31, 2009
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	1,338	$	—	$	1,338	$	—		$	1,338
Other derivative instruments:
Trading commodity		—		3,555		834		4,389		(2,589	)		1,800
Natural gas commodity		—		6,090		—		6,090		111			6,201
Total current derivative liabilities	$	—	$	10,983	$	834	$	11,817	$	(2,478	)		9,339
Purchased power agreements (a)													8,946
Current derivative instruments												$	18,285

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	489	$	883	$	1,372	$	676		$	2,048
Natural gas commodity		—		302		—		302		248			550
Total noncurrent derivative liabilities	$	—	$	791	$	883	$	1,674	$	924			2,598
Purchased power agreements (a)													46,989
Noncurrent derivative instruments												$	49,587

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

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

The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.

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

Index

The following table presents the changes in Level 3 recurring fair value measurements for the years ended Dec. 31, 2010, 2009, and 2008:


	Year Ended Dec. 31,

(Thousands of Dollars)	2010			2009			2008
Balance at Jan. 1	$	804		$	(26	)	$	4,121
Purchases, issuances, and settlements, net		(570	)		(3,668	)		(4,396	)
Transfers (out of) into Level 3		(1,887	)		579			—
Gains (losses) recognized in earnings		1,653			2,535			(1,384	)
Gains recognized as regulatory assets and liabilities		—			1,384			1,633
Balance at Dec. 31	$	—		$	804		$	(26	)

Gains on Level 3 commodity derivatives recognized in earnings for the years ended Dec. 31, 2010 and Dec. 31, 2009 include $1.5 million and $2.6 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2010 and Dec. 31, 2009, respectively. Losses on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $0.8 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008. Realized and unrealized gains and losses on commodity trading activities are included in electric utility revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or are deferred as regulatory assets or liabilities. This classification as a regulatory asset or liability is based on commission approved regulatory mechanisms.

11. Financial Instruments

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


	2010				2009
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Other investments	$	8	$	8	$	8	$	8
Long-term debt, including current portion		3,235,223		3,531,729		2,828,952		3,050,249

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, 2010 and 2009. 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.

Guarantees — In connection with the purchase agreement, Xcel Energy provides for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. See Note 18 to the consolidated financial statements for further information.

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, 2010 and 2009, there were $4.7 million and $4.6 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.

Index

12. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — CPUC

Base Rate

2010 Electric Rate Case — In December 2009, the CPUC approved a rate increase of approximately $128.3 million; however, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. In the first quarter of 2011, the CPUC reconsidered several matters at PSCo’s request and increased that amount by $2.2 million, resulting in an overall rate increase of approximately $130 million.

Under the plan, the following increases have been implemented:

●

A rate increase of $67 million was implemented on Jan. 1, 2010.

●

In May 2010, base rates were increased to recover $125 million annually, when Comanche Unit 3 went into service.

●

Base rates increased to recover approximately $130 million annually on Jan. 1, 2011, to reflect 2011 property taxes.

A second phase of the rate case addressed changes to rate design. The new rates approved by the CPUC went into effect on June 1, 2010. In this phase of the proceeding, the CPUC approved tiered summer rates for residential customers and seasonally differentiated rates for other customer classes, which will impact the timing of revenue collection, as compared to the previous rate design, depending on customer response. Year-to-date electric revenues and margin were positively impacted by approximately $31 million, related to the implementation of such rate design and seasonal rates. Seasonal rates are designed to be revenue neutral on an annual basis. However, the quarterly pattern of revenue collection will is expected to be different than in the past as seasonal rates are higher in the summer months and lower throughout the remainder of the year.

2010 Gas Rate Case — In December 2010, PSCo filed a request with the CPUC to increase Colorado retail gas rates by $27.5 million, effective in the summer of 2011. The request was based on a 2011 forecast test year, a 10.90 percent ROE, a rate base of $1.1 billion and an equity ratio of 57.10 percent. PSCo also proposed that beginning in 2012, it be allowed to recover certain compliance and aging infrastructure costs through a pipeline integrity rider.

Electric, Purchased Gas and Resource Adjustment Clauses

TCA Rider — In November 2010, PSCo filed its annual TCA rider, to adjust the amounts recovered in the rider based on updated plant balances. The filing increased rates by $9.0 million, effective Jan. 1, 2011.

REC Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with sales of Colorado that are RECs bundled with energy into California. In January 2010, PSCo, the OCC, the CPUC staff, the Colorado Governor’s Energy Office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that margins would be shared based on the following allocations:

							Carbon
Margin	Customers			PSCo			Offsets
Less than $10 million		50	%		40	%		10	%
$10 million to $30 million		55			35			10
Greater than $30 million		60			30			10

Amounts designated as carbon offsets are recorded as a regulatory liability until carbon offset-related expenditures are incurred. Carbon offsets are capped at $10 million, with the remaining 10 percent going to customers after the cap is reached. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers. Margins associated with sales of unbundled stand-alone renewable energy credits without energy would be credited 100 percent to customers, and PSCo has the right to file a separate application for sharing margins from stand-alone REC sales. The CPUC approved the settlement in May 2010. Since the settlement, PSCo has filed an application to share margins from the sales of stand alone RECs at 20 percent to PSCo and 80 percent to customers. The application will be decided in the first quarter of 2011. PSCo is expected to file a proposal for permanent treatment of REC margins, excluding the stand-alone margins, in March 2011.

Index

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Case — On Feb. 8, 2011, PSCo filed a request with the FERC to change Colorado wholesale electric customer rates to formula based rates with an expected increase of $16.1 million annually for 2011. PSCo is seeking to make the request effective in April 2011; however, the FERC has the authority to grant a five month suspension from the April date. The request was based on a 2011 forecast test year, a 10.9 percent ROE, a total PSCo wholesale production rate base of $407.4 million and an equity ratio of 57.1 percent. Under the proposal, the formula rate would be estimated each year for the following year and then would be trued up to actual costs after the conclusion of the calendar year. The primary drivers of the revenue deficiency are the inclusion of the recently acquired Blue Spruce Energy Center and Rocky Mountain Energy Center generating units and inclusion of the costs of early retirement of certain coal plants under the CACJA emissions reduction plan, all of which were approved by the CPUC in late 2010.

13. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2010, the estimated cost of capital expenditure programs of PSCo is approximately $700 million in 2011, $820 million in 2012 and $920 million in 2013. PSCo’s capital forecast includes the following major project.

CACJA — The CACJA was signed into law in April 2010. The CACJA aims to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal fired generation identified in the plan. The total cost of the plan would result in new construction of approximately $1.0 billion over the next seven years.

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, legislative initiatives, reserve margins, the availability of purchased power, alternative plans for meeting PSCo’s long-term energy needs, compliance with future requirements and RPS 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 2011 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, 2010, are as follows:

(Millions of Dollars)
Coal	$	327.3
Natural gas supply		1,142.8
Natural gas storage & transportation		1,811.8

Purchased Power Agreements — PSCo has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

Index

PSCo has various pay-for-performance contracts with expiration dates through the year 2034. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for purchase power agreements accounted for as executory contracts were payments for capacity of $275.4 million, $307.7 million, and $323.6 million in 2010, 2009 and 2008, respectively. At Dec. 31, 2010, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, were as follows:

(Millions of Dollars)
2011	$	182.0
2012		122.8
2013		72.5
2014		67.3
2015		72.9
2016 and thereafter		101.7
Total	$	619.2

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

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

PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease in accordance with the authoritative guidance on lease accounting. As a result, PSCo has a $149.9 million capital lease obligation, net of amortization, recorded for the arrangement as of Dec. 31, 2010. WYCO is expected to incur approximately $4.4 million of additional construction costs, 50 percent of which will be paid by Xcel Energy, to finalize construction and make Totem operational at full storage capacity.

Following is a summary of assets held under capital leases:

(Millions of Dollars)	2010			2009
Storage, leaseholds and rights	$	196.1		$	183.6
Gas pipeline		20.7			20.7
Property held under capital lease		216.8			204.3
Accumulated depreciation		(26.6	)		(21.3	)
Total property held under capital leases, net	$	190.2		$	183.0

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 expenses under operating lease obligations was approximately $70.5 million, $80.9 million and $85.6 million for 2010, 2009 and 2008, respectively. These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchase power agreements accounted for as operating leases of $53.8 million, $64.8 million and $67.5 million in 2010, 2009 and 2008, respectively.

Index

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 the applicable accounting guidance. Future commitments under operating and capital leases are:

			Purchase Power
	Other		Agreement		Total
	Operating		Operating		Operating		Capital
(Millions of Dollars)	Leases		Leases (a) (b)		Leases		Leases
2011	$	15.8	$	44.6	$	60.4	$	31.4
2012		14.6		55.7		70.3		29.7
2013		14.1		73.1		87.2		29.5
2014		14.3		79.3		93.6		29.4
2015		14.0		79.7		93.7		27.0
Thereafter		42.1		677.8		719.9		606.8
Total minimum obligation								753.8
Interest component of obligation								(563.6	)
Present value of minimum obligation							$	190.2

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

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

Variable Interest Entities — Effective Jan. 1, 2010, PSCo adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

PSCo purchases power from independent power producing entities that own natural gas fueled power plants. Under certain purchased power agreements with these entities, PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that PSCo purchases. These specific purchased power agreements have been determined by PSCo to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

PSCo is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

PSCo has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M expense, historical and estimated future fuel and electricity prices, and financing activities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. As of Dec. 31, 2010 and Dec. 31, 2009, PSCo had approximately 2,921 MW of capacity under long term purchased power agreements with entities that have been determined to be variable interest entities.

Environmental Contingencies

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

Site Remediation — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. 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 manufactured gas plants operated by PSCo, its predecessors, or other entities; and third-party sites, such as landfills, for which PSCo is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.8 million and $0.9 million, respectively, of which $0.3 million was considered to be a current liability.

Index

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

Other Environmental Requirements

EPA GHG Endangerment Rulemaking — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations became applicable in 2011. In December 2010, the EPA announced a settlement with several states and environmental groups to begin preparing regulations of emissions from both new and existing steam electric generating units, such as coal-fired power plants, under Section 111 of the CAA. The EPA plans to propose these regulations in July 2011 and finalize them in the first half of 2012.

CAMR — In 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 the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR. PSCo anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years. Costs associated with such requirements are uncertain at this time.

Colorado Mercury Regulation — Colorado’s mercury regulations require mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by the end of 2011. 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 sorbent expense. PSCo has evaluated the Colorado mercury control requirements for its other units in Colorado and believes that, under current regulations, no further controls will be required other than the planned controls at the Pawnee Generating Station. The Pawnee mercury controls are included in the CACJA plan.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules, including provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States.

In 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate, install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. The CAPCD has indicated that it expects to submit a Regional Haze BART/Reasonable Further Progress SIP to the EPA for approval in 2011. In January, 2011, the Colorado Air Quality Commission approved a revised Regional Haze BART/Regional Further Progress SIP incorporating the Colorado CACJA emission reduction plan. In accordance with Colorado law, the SIP is now before the Colorado general assembly for review prior to submission to the EPA. PSCo anticipates that for those plants included in CACJA emission reduction plan, the plan will satisfy regional haze requirements. The Colorado SIP, however, must be approved by the EPA. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2017.

In March 2010, two environmental groups petitioned the U.S. Department of the Interior to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. Four PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the U.S. Department of the Interior will rule on the petition.

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 BTA for minimizing adverse environmental impacts. In 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 challenging the phase II rulemaking. In April 2009, the U.S. Supreme Court issued a decision concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

Index

Proposed Coal Ash Regulation — Xcel Energy’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, Xcel Energy’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. Xcel Energy submitted comments to the EPA on Nov. 19, 2010 indicating its support of the development of regulations to manage coal ash as a nonhazardous waste. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

PSCo Notice of Violation (NOV) — In 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid to late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo also 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 the applicable accounting guidance. This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

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

PSCo recognized an ARO for the retirement costs of its natural gas mains and for the removal of electric, transmission and distribution equipment. The electric transmission and distribution ARO consists of many small potential obligations associated with 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, 2010 and 2009, respectively:

	Beginning								Revisions		Ending
	Balance		Liabilities		Liabilities				to Prior		Balance
(Thousands of Dollars)	Jan. 1, 2010		Recognized		Settled		Accretion		Estimates		Dec. 31, 2010
Electric plant
Steam production asbestos	$	59,724	$	—	$	—	$	3,907	$	—	$	63,631
Steam production ash containment		4,587		32		—		272		1,637		6,528
Steam production radiation sources		118		—		—		8		1		127
Electric transmission and distribution		115		—		—		7		1,624		1,746
Natural gas plant
Gas transmission and distribution		616		—		—		39		—		655
Total liability	$	65,160	$	32	$	—	$	4,233	$	3,262	$	72,687

Index

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


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

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

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 records a regulatory liability for plant removal costs for generation, transmission and distribution facilities. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2010 and Dec. 31, 2009 were $385 million and $375 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

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of PSCo, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. 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 September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and is currently on appeal before the United States Supreme Court. Oral arguments will be presented to the Supreme Court on April 19, 2011 and a decision is expected in the summer of 2011.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of PSCo, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs’ subsequent appeals of this decision were unsuccessful, rendering the District Court’s dismissal the final determination.

Index

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of PSCo, and 23 other utilities, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs alleged relocation is estimated to cost between $95 million to $400 million. No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Qwest vs. Xcel Energy Inc. — In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. In April 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. In February 2010, the Colorado Supreme Court agreed to review the Court of Appeals’ decision as to the punitive damages issue but will not review the Court of Appeals’ decision as it relates to PSCo. Oral arguments were presented in December 2010. It is unknown when the Colorado Supreme Court will render a decision. No accrual has been recorded for this matter.

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 (CCH) near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal OSHA, the CSB and the Colorado Bureau of Investigations.

In March 2008, OSHA proposed penalties totaling $189,900 for 22 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. Pursuant to a court order this proceeding has been stayed until July 1, 2011.

Three lawsuits were filed (two in Colorado state court and one in California state court) on behalf of the five deceased workers and by seven employees of RPI allegedly injured in the accident. PSCo and Xcel Energy were among the defendants named in each lawsuit. Settlements were subsequently reached in all three lawsuits by Xcel Energy and PSCo. These confidential settlements did not have a material adverse effect upon Xcel Energy’s consolidated results of operations, cash flows or financial position.

In August 2009, the U.S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. In September 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. The trial date has been set for May 31, 2011. No accrual has been recorded for this proceeding nor is it expected that this proceeding will have a material adverse effect upon PSCo’s consolidated results of operations, cash flows or financial position.

In August 2010, the CSB issued a report related to its investigation of the CCH accident. The report contains several findings and recommendations, some of which pertain to PSCo. Consistent with its delegated authority, the CSB investigation did not result in the issuance of any fines or penalties. PSCo has responded to the CSB concerning its recommendations.

Stone & Webster, Inc. vs. PSCo — In July 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages. The complaint also alleges that Xcel Energy and related entities guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. In total, Shaw seeks approximately $144 million in damages.

Index

PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled to liquidated damages and excess costs incurred. In total, PSCo is seeking approximately $82 million in damages. In June 2010, PSCo exercised its contractual right to draw on Shaw’s letter of credit in the total amount of approximately $29.6 million. In September 2010, Shaw filed a second lawsuit related to PSCo’s decision to draw on the letter of credit. PSCo denied the merits of this claim.

Trial commenced in October 2010 and addressed only those issues raised in the first complaint and did not include Shaw’s claim asserted in the second lawsuit related to the letter of credit. In November 2010, a jury returned a verdict that awarded damages to Shaw and to PSCo. Specifically the jury awarded a total of $84.5 million to Shaw but also awarded $70.0 million to PSCo for damages related to its counterclaims, for a net verdict to Shaw in the amount of $14.5 million. Shaw subsequently filed post trial motions, which the court denied. It is uncertain whether Shaw will file an appeal. If the jury verdict remains unchanged it is not expected to have a material adverse effect on PSCo’s consolidated results of operations, cash flows or financial position.

Connie DeWeese vs. PSCo — In November 2008, there was an explosion in Pueblo, Colo., which destroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms have determined a natural gas leak from a pipeline under the street led to the explosion. In February 2010, a wrongful death/personal injury lawsuit was filed in Colorado District Court in Pueblo, Colorado against PSCo and the City of Pueblo by several parties that were allegedly injured, as a result of this explosion. The plaintiffs are also alleging economic and noneconomic damages. The lawsuit alleges that the accident occurred as a result of PSCo’s negligence. A related lawsuit was filed in March 2010 by Seneca Insurance Company, which insured Branch Inn, LLC and Branch Inn Enterprises, LLC. The plaintiffs are alleging destruction of the building and disruption of the business. Both lawsuits allege that the accident occurred as a result of PSCo’s negligence. PSCo denies liability for this accident. The cases have been consolidated. In June 2010, the court granted, in part, PSCo’s motion to dismiss certain of plaintiffs’ claims related to, among other things, strict liability. In July 2010, a third related lawsuit was filed by Truck Insurance Exchange against PSCo and the City of Pueblo to recover damages allegedly paid by the plaintiff insurance company to its insured as a result of the explosion. In September 2010, six plaintiffs filed a fourth lawsuit, Vigil vs. Xcel Energy, in Hennepin County District Court in Minneapolis, Minn., alleging personal injury and property damage as a result of the November 2008 explosion. In January 2011, the court granted Xcel Energy’s motion to dismiss this lawsuit on procedural grounds. The damages claimed by plaintiffs in the three Colorado lawsuits are presently unknown but it is not believed that this total, if recovered, would have a material adverse effect upon Xcel Energy’s consolidated results of operations, cash flows or financial position. No trial date has been set for these lawsuits.

14. Regulatory Assets and Liabilities

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

Index

The components of regulatory assets and liabilities shown on the consolidated balance sheets of PSCo at Dec. 31, 2010 and Dec. 31, 2009 are:

		See	Remaining
(Thousands of Dollars)		Note(s)	Amortization Period	Dec. 31, 2010						Dec. 31, 2009
				Current		Noncurrent			Current			Noncurrent
Regulatory Assets
Recoverable purchased natural gas and electric energy costs	1		Less than one year	$	18,622		$	—		$	25,157		$	—
Pension and employee benefit obligations (a)	8		Various		44,917			551,505			36,300			524,430
AFUDC recorded in plant (b)	1		Plant lives		—			92,444			—			88,849
Contract valuation adjustments (c)	10		Term of related contract		43,368			26,498			—			—
Renewable and environmental initiative costs	13		One to six years		47,961			4,500			25,984			5,181
Net AROs (d)	1,13		Plant lives		—			43,227			—			33,725
Conservation programs (b)	1		Typically one to two years		7,770			30,464			25,748			32,548
Gas pipeline inspection costs			Pending rate case		2,000			25,082			2,542			10,234
Purchased power contracts costs	10,13		Term of related contract		—			18,549			—			13,189
Depreciation differences			One to seven years		5,859			12,379			—			—
Losses on reacquired debt	1		Term of related debt		1,912			14,750			1,912			16,662
Other			Various		4,187			4,807			4,518			5,489
Total regulatory assets				$	176,596		$	824,205		$	122,161		$	730,307

Regulatory Liabilities
Deferred electric, gas, and steam production costs	1			$	44,921		$	—		$	64,552		$	—
Plant removal costs	1,13				—			384,640			—			374,555
Investment tax credit deferrals	1				—			29,014			—			30,662
REC margin sharing	1,12		Pending future rate case		—			26,104			—			—
Deferred income tax adjustment	1				—			20,938			—			21,771
Low income discount program					4,706			4,032			2,526			2,017
Gain from asset sales	1		Pending future rate case		—			6,700			—			10,329
Contract valuation adjustments (c)	10				—			—			12,312			53,329
Other					391			1,418			1,074			1,916
Total regulatory liabilities				$	50,018		$	472,846		$	80,464		$	494,579

(a)

Includes $7.8 million and $11.7 million of unamortized prior service costs at Dec. 31, 2010 and Dec. 31, 2009, respectively. These amounts are offset by $4.5 and $4.2 million of regulatory assets related to the non-qualified pension plan of which $0.4 million is included in the current asset at Dec. 31, 2010 and Dec. 31, 2009.

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

(c)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.

(d)	Includes amounts recorded for future recovery of AROs.

15. Segments and Related Information

PSCo has the following reportable segments: regulated electric, regulated natural gas and all other.

●

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

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

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

Index

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. 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.

Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

	Regulated			Regulated			All				Reconciling				Consolidated
(Thousands of Dollars)		Electric		Natural Gas			Other				Eliminations				Total
2010
Operating revenues from external customers		$	3,055,045		$	1,075,446		$	33,879			$	—			$	4,164,370
Intersegment revenues			236			154			—				(390	)			—
Total revenues		$	3,055,281		$	1,075,600		$	33,879			$	(390	)		$	4,164,370

Depreciation and amortization		$	226,374		$	53,535		$	4,230			$	—			$	284,139
Interest charges and financing costs			133,518			29,623			3,497				—				166,638
Income tax expense (benefit)			198,139			36,278			(5,236	)			—				229,181
Net income			299,148			70,279			30,293				—				399,720

2009
Operating revenues from external customers		$	2,678,578		$	1,093,959		$	35,772			$	—			$	3,808,309
Intersegment revenues			266			79			—				(345	)			—
Total revenues		$	2,678,844		$	1,094,038		$	35,772			$	(345	)		$	3,808,309

Depreciation and amortization		$	200,776		$	50,795		$	4,491			$	—			$	256,062
Interest charges and financing costs			121,434			25,242			1,084				—				147,760
Income tax expense (benefit)			123,047			57,375			(10,017	)			—				170,405
Net income			242,265			67,288			13,767				—				323,320

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

Depreciation and amortization		$	190,544		$	55,638		$	6,202			$	—			$	252,384
Interest charges and financing costs			110,263			25,505			279				—				136,047
Income tax expense (benefit)			132,315			53,075			(18,762	)			—				166,628
Net income			230,417			87,505			21,874				—				339,796

Index

16. 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 to the consolidated financial statements for further discussion.

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

(Thousands of Dollars)	2010		2009		2008
Operating revenues:
Electric	$	9,428	$	7,751	$	38,625
Other		3,331		4,441		4,459
Operating expenses:
Purchased power		6,805		5,976		7,000
Other operating expenses — paid to Xcel Energy Services Inc.		307,136		295,934		285,423
Interest expense		104		586		1,361

Accounts receivable and payable with affiliates at Dec. 31 were:

	2010				2009
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	6,674	$	—	$	15,789	$	—
NSP-Wisconsin		164		—		30		—
SPS		2,606		—		—		239
Other subsidiaries of Xcel Energy		11,598		28,270		17,577		40,519
	$	21,042	$	28,270	$	33,396	$	40,758

17. 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, 2010		June 30, 2010		Sept. 30, 2010		Dec. 31, 2010
Operating revenues	$	1,202,697	$	947,296	$	954,970	$	1,059,407
Operating income		201,078		156,677		243,055		154,242
Net income		84,250		77,685		158,091		79,694

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

Index

18. Acquisition of Generation Assets

In December 2010, PSCo purchased the Blue Spruce Energy Center and Rocky Mountain Energy Center from Calpine Development Holdings, Inc. and Riverside Energy Center LLC for $739.0 million plus an additional $3.0 million for working capital adjustments. The working capital adjustments consisted of the settlement of PSCo’s most recent purchases of energy and capacity under the terminated purchased power agreements, adjusted for accrued operating liabilities of the acquired plants of $6.5 million.

The Blue Spruce Energy Center is a 310 MW simple cycle natural gas-fired power plant that began commercial operations in 2003. The Rocky Mountain Energy Center is a 652 MW combined-cycle natural gas-fired power plant that began commercial operations in 2004. Both power plants previously provided energy and capacity to PSCo under purchased power agreements, which were set to expire in 2013 and 2014, respectively. The acquisition developed out of PSCo’s resource planning activities, in which customers’ future energy needs are addressed in a formal planning process for meeting PSCo’s generation obligations, considering various assumptions and objectives including prices, reliability, and emissions levels. The generation assets were offered to PSCo as a competitive bid in the resource planning process, and the offer was the least cost option for thermal generation resources.

The purchase price has been allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:

(Thousands of Dollars)
Assets acquired
Inventory	$	3,834
Property, plant and equipment		735,916
Total assets acquired		739,750

Liabilities assumed
Accrued expenses		7,255
Total liabilities assumed		7,255

Net assets acquired	$	732,495

The purchase agreement allows PSCo 90 days to review and approve the working capital adjustment based on an examination of the plants’ books and records. If subsequent to the acquisition date, information is obtained about conditions that existed at the acquisition date that indicate the initial recorded amounts should be adjusted, adjustments may be recorded in 2011 to the assets acquired and liabilities assumed in the acquisition.

Operating results for the plants subsequent to the date of acquisition are included in the Consolidated Statement of Income for the Year Ended Dec. 31, 2010. PSCo incurred approximately $1.2 million of recoverable acquisition-related legal and consulting costs that are deferred as a regulatory asset as of Dec. 31, 2010.

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

During 2009 and 2010, and through the date of this report, there were no disagreements with the independent public accountants for PSCo on accounting principles or practices, financial statement disclosures or audit scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2010, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.

Index

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, 2010 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 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 and Related Transactions, and Director Independence

Item 14 — Principal Accountant Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2011 Annual Meeting of Shareholders, which is incorporated by reference.

Index

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements:

Management Report on Internal Controls — For the year ended Dec. 31, 2010.

Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2010, 2009 and 2008.

Consolidated Statements of Income — For the three years ended Dec. 31, 2010, 2009 and 2008.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2010, 2009 and 2008.

Consolidated Balance Sheets — As of Dec. 31, 2010 and 2009.

2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2010, 2009 and 2008.

Exhibits

	*Indicates incorporation by reference
	+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
	t Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed separately with the SEC.

2.01* t	Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request). (Exhibit 2.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2010).
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, between PSCo and Morgan Guaranty Trust Company of New York, as trustee, 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, between PSCo and Morgan Guaranty Trust Company of New York, as trustee,:

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

Nov. 1, 1993	S-3, (33-51167)	4(b)(2)
Jan. 1, 1994	10-K, 1993	4(b)(3)
Sept. 2, 1994	8-K, September 1994	4(b)
May 1, 1996	10-Q, June 30, 1996	4(b)
Nov. 1, 1996	10-K, 1996 (001-03280)	4(b)(3)
Feb. 1, 1997	10-Q, March 31, 1997 (001-03280)	4(a)
April 1, 1998	10-Q, March 31, 1998 (001-03280)	4(b)
Aug. 15, 2002	10-Q, Sept. 30, 2002 (001-03280)	4.03
Sept. 1, 2002	8-K, Sept. 18, 2002(001-03280)	4.01
Sept. 15, 2002	10-Q, Sept. 30, 2002(001-03280)	4.04
March 1, 2003	S-3, April 14, 2003 (333-104504)	4(b)(3)
April 1, 2003	10-Q May 15, 2003 (001-03280)	4.02
May 1, 2003	S-4, June 11, 2003 (333-106011)	4.9
Sept. 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.02
Sept. 15, 2003	Xcel 10-K, March 15, 2004 (001-03034)	4.100
Aug. 1, 2005	PSCo 8-K, Aug. 18, 2005 (001-03280)	4.02
Aug. 1, 2007	PSCo 8-K, Aug. 14, 2007 (001-03280)	4.01
Nov. 1, 2010	PSCo 8-K, Nov. 8, 2010 (001-03280)	4.01

4.03*

Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).

Index

4.04*	Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*	Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust NA, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
4.06*	Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $300,000,000 principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300,000,000 principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
4.07*	Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $400,000,000 principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
4.08*	Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank Trust NA, as successor Trustee, creating $400,000,000 principal amount of 3.200 percent First Mortgage Bonds, Series No. 21 due 2020 (Exhibit 4.01 of Form 8-K of PSCo dated Nov. 16, 2010 (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 Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Amended and Restated Executive Long-Term Incentive Award Stock Plan (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+	New Century Energies Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+	Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+	Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement of Xcel Energy Form (file no. 001-03034) dated April 11, 2005).
10.14*+	Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement of Xcel Energy Form (file no. 001-03034) dated April 11, 2005).
10.15*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10I(1)).
10.17*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10I(2)).
10.18*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.19*	Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.20*	Amendment dated as of April 13, 2009 to the PSCo Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.21*	Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.22*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).

Index

10.23*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.24*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.25*+	Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.26*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.27*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.28*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.29*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.30*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
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.

Index

SCHEDULE II

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2010, 2009 and 2008

(amounts in thousands of dollars)

				Additions
				Charged to			Charged to			Deductions
	Balance at			costs and			other			from			Balance at
	Jan. 1			expenses			accounts (a)			reserves (b)			Dec. 31
Reserve deducted from related assets:
Allowance for bad debts:
2010		$	24,149		$	21,571		$	7,192		$	28,858		$	24,054
2009			29,195			21,189			14,364			40,599			24,149
2008			23,301			28,372			8,146			30,624			29,195

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

Index

SIGNATURES

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

	PUBLIC SERVICE COMPANY OF COLORADO

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

February 28, 2011

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

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

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

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

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

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

Attached files

PUBLIC SERVICE CO OF COLORADO Reports

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