Public Service Co Of Colorado 10-K 2006 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to

COMMISSION FILE NUMBER 001-03280

PUBLIC SERVICE COMPANY OF COLORADO

(Exact name of registrant as specified in its charter)

Colorado	84-0296600
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
1225 17th Street
Denver, Colorado 80202
(Address of principal executive offices)
(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

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 by Rule 405 of the Securities Act. o Yes or No ý

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

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. Yes  ý   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). o Large accelerated filer o Accelerated filer ý Non-accelerated filer

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

As of Feb. 26, 2007, 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 2007 Proxy Statement, to be filed subsequently

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

INDEX

General Electric Utility Pending Regulatory Matters

Trading Operations

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

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NSP-Minnesota	Northern States Power Co., a Minnesota corporation
NSP-Wisconsin	Northern States Power Co., a Wisconsin corporation
PSCo	Public Service Company of Colorado, a Colorado corporation
PSRI	PSR Investments, Inc.
SPS	Southwestern Public Service Co., a New Mexico corporation
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy	Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
CPUC	Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo’s operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, and the sale of electricity at wholesale, in interstate commerce, including the sale of electricity at market-based rates.
IRS	Internal Revenue Service
OCC	Colorado Office of Consumer Counsel
SEC	Securities and Exchange Commission
Fuel, Purchased Gas and Resource Adjustment Clauses
AQIR	Air-quality improvement rider. Recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
DSM	Demand-side management. Energy conservation and weatherization program for low-income customers.
DSMCA	Demand-side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA	Retail electric commodity adjustment. The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The current ECA mechanism expired Dec. 31, 2006. Effective Jan. 1, 2007 the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism will be revised quarterly and interest will accrue monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.
GCA	Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
ICA	Incentive cost adjustment. A retail adjustment clause that allowed PSCo to equally share between electric customers and shareholders certain fuel and

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	purchased energy costs and expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs was amortized over the period June 1, 2002 through March 31, 2005.
IAC	Interim adjustment clause. A retail adjustment clause that allowed PSCo to recover prudently incurred fuel and energy costs not included in electric base rates. This clause expired Dec. 31, 2003.
PCCA	Purchased capacity cost adjustment. Allows PSCo to recover from customers purchased capacity payments to power suppliers under specifically identified power purchase agreements not included in the determination of PSCo’s base electric rates or other recovery mechanisms. This clause expired in 2006. A new PCCA clause will become effective Jan. 1, 2007 permits recovery from retail customers for all purchased capacity payments to power suppliers. Capacity charges are not included in PSCo’s base electric rates or other recovery mechanisms.
QSP	Quality of service plan. Provides for bill credits to retail customers if the utility does not achieve certain operational performance targets and/or specific capital investments for reliability. The current QSP for PSCo and SPS electric utility expired in 2006. A new QSP for the PSCo electric utility provides for bill credit to customers based upon operational performance standards through Dec. 31, 2010.The QSP for the PSCo gas utility expires December 2007.
SCA	Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
Other Terms and Abbreviations
AFDC	Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
ARO	Asset Retirement Obligation.
COLI	Corporate-owned life insurance.
deferred energy costs	The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
		·     An underlying and a notional amount or payment provision or both,
		·     Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
		·     Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ERISA	Employee Retirement Income Security Act
FASB	Financial Accounting Standards Board
FTRs	Financial Transmission Rights
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
C20	Derivatives Implementation Group of FASB Implementation Issue No. C20.

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	Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.
JOA	Joint operating agreement among the Utility Subsidiaries
LDC	Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas. Natural gas that has been converted to a liquid by cooling it to — 260 degrees Fahrenheit.
mark-to-market	The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in current earnings in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator
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.
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
OMOI	FERC Office of Market Oversight and Investigations
PBRP	Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PUHCA	Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.
PUHCA 2005	Public Utility Holding Company Act of 2005. Successor to the Public Utility Holding Company Act of 1935. Eliminates most federal regulation of utility holding companies. Transfers other regulatory authority from the SEC to FERC.
QF	Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
rate base	The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
RCR	Renewable Cost Recovery
ROE	Return on equity
RTO	Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS	Statement of Financial Accounting Standards
SMA	Supply margin assessment
SMD	Standard market design
SO2	Sulfur dioxide
TEMT	Transmission and Energy Markets Tariff
TRANSLink	TRANSLink Transmission Co., LLC
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.

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VaR	Value-at-risk
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.
working capital	Funds necessary to meet operating expenses
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.
Bcf	Billion cubic feet
Dth	Dekatherm (one Dth is equal to one MMBtu)
KV	Kilovolts
KW	Kilowatts
Kwh	Kilowatt hours
MMBtu	One million BTUs
MW	Megawatts (one MW equals one thousand KW)
Mwh	Megawatt hour. One Mwh equals one thousand Kwh.
Watt	A measure of power production or usage equal to the kinetic energy of an object with a mass of 2 kilograms moving with a velocity of one meter per second for one second.

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COMPANY OVERVIEW

PSCo was incorporated in 1924 under the laws of Colorado.  PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo serves approximately 1.3 million electric customers and approximately 1.3 million natural gas customers in Colorado.  The wholesale customers served by PSCo comprised approximately 22 percent of the total Kwh sales in 2006.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2006.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; PSRI, which owns and manages permanent life insurance policies on certain current and former employees; and Green and Clear Lakes Company, which owns water rights.  PSCo also holds a controlling interest in several other relatively small ditch and water companies.

ELECTRIC UTILITY OPERATIONS

Overview

Utility Industry Growth — PSCo intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers.  PSCo plans to continue to file rate cases with state and federal regulators to earn a return on its investment and recover costs of operations.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change.  Merger and acquisition activity had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future.  The FERC has implemented wholesale electric utility competition, and the wholesale customers of Xcel Energy’s utility subsidiaries can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ use to serve their native load.  Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition.

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of PSCo. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 11 to the Consolidated Financial Statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) - The Energy Act repealed PUHCA effective Feb. 8, 2006.  In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completed or initiated the proceedings to modify its regulations on a number of subjects, including:

·Adopting new regulations by establishing rules for accounting procedures for holding company systems, including cost allocation rules for transactions between companies within a holding company system;

·Adopting new regulations to implement changes to the FERC’s merger and asset transfer authority;

·Adopting new “market manipulation regulations” prohibiting any “manipulative or deceptive device or contrivance” in wholesale natural gas and electricity commodity and transportation or transmission markets and interpreting this standard in a manner consistent with Rule 10b-5 of the SEC; violations are subject to potential civil penalties of up to $1 million per day;

·Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary North American Electric Reliability Council (NERC) structure, and requiring the ERO to establish mandatory reliability standards and imposition of financial or other penalties for violations of adopted standards.  The FERC has issued proposed rules to make 83 ERO reliability standards mandatory and subject to potential financial penalties for non-compliance to be effective June 1, 2007;

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·Adopting rules to implement changes to the Public Utility Regulatory Policy Act to allow utility ownership of QFs and strengthening the thermal energy requirements for entities seeking to be QFs;

·Proposing rules that would allow a utility to seek to eliminate its mandatory QF power purchase obligation for utilities in organized wholesale energy markets; and

·Adopting rules to establish incentives for investment in new electric transmission infrastructure.

PSCo generally supports the regulations adopted or proposed by the FERC to date, but cannot predict the ultimate impact the new regulations will have on its operations or financial results.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility 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. .  PSCo is currently participating with other utilities in the development of WestConnect, which would provide certain regionalized transmission and wholesale energy market functions but would not be an RTO.

Ratemaking Principles

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, wholesale sales for resale and the transmission of electricity in interstate commerce.

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, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provided for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The current ECA mechanism expired Dec. 31, 2006.  Effective Jan. 1, 2007, the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy.  The total incentive payment to PSCo in any calendar year will not exceed $11.25 million.  The ECA mechanism will be revised quarterly and interest will accrue monthly on the average deferred balance.  The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service, or Dec. 31, 2010.

·PCCA — The PCCA, which became effective June 1, 2004, allows for recovery of purchased capacity payments to certain power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms.  Effective Jan. 1, 2007, all prudently incurred purchased capacity costs will be recovered through the PCCA.  The PCCA will expire at the earlier of rates taking effect after Comanche 3 is placed in service, or Dec. 31, 2010.

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

·AQIR — The AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan, effective Jan. 1, 2003, to reduce emissions and improve air quality in the Denver metro area.

·DSMCA — The DSMCA clause permits PSCo to recover DSM costs beginning Jan. 1, 2006 over eight years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. DSM costs incurred prior to Jan. 1, 2006 are recovered over 5 years.  PSCo also has a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA.

·Renewable Energy Service Adjustment (RESA) — The RESA recovers costs associated with complying with the provisions of a citizen referred ballot initiative passed in 2004 that establishes a renewable portfolio standard for PSCo’s electric customers.  Currently, the RESA recovers the incremental costs of compliance with the renewable energy standard and is set at a level of 0.6 percent of the net costs.

·Wind Energy Service Adjustment (WESA) - The WESA provides for the recovery of certain costs associated with the provision of wind energy resources from those customers subscribed as WindSource renewable energy customers.

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PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause accepted for filing by the FERC.

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

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

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

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

For a further discussion of rate and regulatory matters see Note 11 to the Consolidated Financial Statements.

Capacity and Demand

The uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2007, assuming normal weather, are listed below.

	System Peak Demand (in MW)
	2004	2005	2006	2007 Forecast
PSCo	6,483	6,975	6,757	6,751

The peak demand for PSCo’s system typically occurs in the summer. The 2006 uninterrupted system peak demand for PSCo occurred on July 19, 2006.

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its system capacity requirements through existing electric generating stations, purchases from other utilities, independent power producers and power marketers, new generation facilities, demand-side management options and phased expansion of existing generation at select power plants.

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

PSCo also makes short-term purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

PSCo Resource Plan — PSCo estimates it will purchase approximately 39 percent of its total electric system energy needs for 2007 and generate the remainder with PSCo-owned resources.  Additional capacity has been secured under contract making additional energy available for purchase, if required. PSCo currently has under contract or through owned generation, the resources necessary to meet its anticipated 2007 load obligation.

In 2004, PSCo filed a least-cost resource plan (LCP) with the CPUC.  PSCo’s proposed to meet future resource needs through a combination of utility built generation, DSM, and power purchases.  The CPUC approved PSCo’s plan to construct a 750 MW pulverized coal-fired unit at the existing Comanche power station located near Pueblo, Colo. and install additional emission control equipment on the two existing Comanche station units.  The CPUC also called for PSCo to acquire the remaining resource needs through an all-source competitive bidding process.

PSCo began construction of the facility in the fall of 2005, which is planned for completion in the fall of 2009.  Based on CPUC approval, construction costs are limited for the Comanche 3 project (i.e., the new unit and the emission controls on existing units 1 and 2). The CPUC also approved a regulatory plan that authorizes PSCo to increase the equity component of its capital structure up to 60 percent to offset the debt equivalent value of PSCo’s existing power purchase contracts and to otherwise improve

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PSCo’s financial strength.  Depending upon PSCo’s senior unsecured debt rating during the time of PSCo general rate cases, the approved settlement permits PSCo to include various amounts of construction work in progress that are associated with the Comanche 3 project in rate base without an offset for allowance for funds used during construction.

PSCo has signed agreements with Intermountain Rural Electric Association (IREA) that define the respective rights and obligations of PSCo and IREA in the transfer of capacity ownership in the Comanche 3 unit.  PSCo and Holy Cross have agreed to terms for Holy Cross ownership of a share of Comanche 3 and Holy Cross has been making its agreed-upon contributions toward construction of the plant.

For the remaining resource needs, PSCo selected bids for approximately 30 MW of DSM resources, approximately 1,300 MW of gas-fired generation resources and approximately 775 MW of wind generation resources.  These bids, together with Comanche 3, and the additional DSM agreed to in the LCP settlement agreement, are expected to meet PSCo’s resource needs through 2012.

Renewable Energy Portfolio Standards — In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard (RES) for electric service.  The law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources.  During 2006, the CPUC determined that compliance with the RES should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on the issue; that Colorado utilities should be required to file implementation plans; and the methods utilities should use for determining the budget available for renewable resources.  In April 2006, the CPUC issued rules that establish the process utilities are to follow in implementing the RES.  PSCo filed its first annual compliance plan under these rules on Aug. 31, 2006.  The plan demonstrates that PSCo is expected to meet the RES beginning in 2007 as required.

On Aug. 31, 2006, PSCo filed with the CPUC an application for approval of its 2007 compliance plan for the RES rules.  As a part of its plan, PSCo requested approval to continue its existing 0.60 percent RES adjustment rider.  Through its existing resources and contracts entered into in 2006, PSCo anticipates having sufficient non-solar renewable energy resources to meet the standard through at least 2016.  In June 2006, PSCo issued a request for proposal to provide solar renewable energy credits and expects to enter into contracts to meet its obligation for customer-sited solar resources.  On Sept. 1, 2006, PSCo executed a twenty-year solar power purchase agreement, which are expected to provide about 16,000 MW hours per year and accompanying solar renewable energy credits beginning in 2008.

RESA — On Dec. 1, 2005, PSCo filed with the CPUC to implement a new 1-percent rider that would apply to each customer’s total electric bill generating approximately $22 million in annual revenue.  The revenues collected under the RESA will be used to acquire sufficient solar resources to meet the on-site solar system requirements in the Colorado statutes.  On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the RESA rider to 0.60 percent and to provide monthly reports.  The RESA rider was approved by the CPUC effective March 1, 2006.

Purchased Transmission Services — PSCo has contractual arrangements with regional transmission service providers to deliver power and energy to PSCo’s native load customers, which are retail and wholesale load obligations with terms of more than one year.

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.

	Coal				Natural Gas				Average Fuel
	Cost		Percent		Cost		Percent		Cost
2006	$	1.24	85	%	$	6.52	15	%	$	2.01
2005	$	1.01	85	%	$	7.56	15	%	$	2.00
2004	$	0.89	87	%	$	5.61	13	%	$	1.52

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

Fuel Sources — Coal inventory levels may vary widely among plants.  However, PSCo normally maintains approximately 30 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2006, were approximately 30 days usage, based on the maximum burn rate for all of PSCo’s coal-fired plants.  PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming.  During 2006, PSCo’s

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coal requirements for existing plants were approximately 10 million tons.

PSCo has contracted for coal suppliers to supply approximately 98 percent of its coal requirements in 2007, 70 percent of its coal requirements in 2008 and 60 percent of its coal requirements in 2009.  Any remaining requirements will be purchased on the spot market.

PSCo has coal transportation contracts that provide for delivery of approximately 100 percent of 2007 coal requirements, 100 percent of 2008 coal requirements and 40 percent of 2009 coal requirements.  Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

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 short- and intermediate- term contracts.  This natural gas is transported to the plants on various interstate pipeline systems with contracts that expire in various years from 2007 through 2025.  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, 2006, PSCo’s commitments related to these contracts were approximately $328 million.

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 minimize commodity price and credit risk and hedge supplies and purchases.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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PSCo Electric Operating Statistics

	Year Ended Dec. 31,
	2006			2005			2004
Electric Sales (Millions of Kwh)
Residential	8,557			8,390			8,066
Commercial and Industrial	18,398			17,857			17,409
Public Authorities and Other	243			234			252
Total Retail	27,198			26,481			25,727
Sales for Resale	7,820			8,112			8,372
Total Energy Sold	35,018			34,593			34,099
Number of Customers at End of Period
Residential	1,113,293			1,091,072			1,083,872
Commercial and Industrial	147,349			145,520			144,111
Public Authorities and Other	60,381			62,985			66,797
Total Retail	1,321,023			1,299,577			1,294,780
Wholesale	49			62			69
Total Customers	1,321,072			1,299,639			1,294,849
Electric Revenues (Thousands of Dollars)
Residential	$	756,701		$	760,919		$	672,496
Commercial and Industrial	1,251,390			1,240,697			1,080,660
Public Authorities and Other	38,775			38,977			36,257
Total Retail	2,046,866			2,040,593			1,789,413
Wholesale	408,859			416,503			403,155
Other Electric Revenues	49,720			46,932			2,060
Total Electric Revenues	$	2,505,445		$	2,504,028		$	2,194,628
Kwh Sales per Retail Customer	20,589			20,377			19,870
Revenue per Retail Customer	$	1,549.46		$	1,570.20		$	1,382.02
Residential Revenue per Kwh	8.84		¢	9.07		¢	8.34		¢
Commercial and Industrial Revenue per Kwh	6.80		¢	6.95		¢	6.21		¢
Wholesale Revenue per Kwh	5.23		¢	5.13		¢	4.82		¢

NATURAL GAS UTILITY OPERATIONS

Summary of Recent Regulatory Developments

The most significant recent developments in the natural gas operations of PSCo have been the continued volatility in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies.  From 1996 to 2006, average annual sales to the typical PSCo residential customer declined from 99 MMBtu per year to 80 MMBtu per year on a weather-normalized basis.  Although recent wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.

Ratemaking Principles

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

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

·     GCA — The GCA mechanism allows PSCo to recover its actual costs of purchased gas, including costs for upstream pipeline services PSCo incurs to meet the requirements of its local distribution system customers.  The GCA is revised monthly to allow for changes in gas rates.

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

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

For a further discussion of rate and regulatory matters see Note 11 to the Consolidated Financial Statements.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,816,362 MMBtu.  In addition, firm transportation customers hold 534,761 MMBtu for PSCo of capacity without supply backup.  Total firm delivery obligation for PSCo is 2,351,123 MMBtu per day.  The maximum daily deliveries for PSCo in 2006 for firm and interruptible services were 1,872,640 MMBtu on Feb. 17, 2006.

PSCo purchases natural gas from independent suppliers.  These purchases are generally priced based on market indices that reflect current prices.  The natural gas is delivered under natural gas transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of approximately 1,618,864 MMBtu/day, which includes 831,866 MMBtu of supplies held under third-party underground storage agreements.  In addition, PSCo operates three company-owned underground storage facilities, which provide about 40,000 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 has closed the Leyden Storage Field and is in the monitoring phase of the abandonment process, which is expected to continue until December 2007.  See further discussion in Item 1, Environmental Matters.

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 period beginning July 1 through June 30 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 12-month period ending the previous June 30.

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:

2006	$	7.09
2005	$	8.01
2004	$	6.30

PSCo has certain 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, 2006, PSCo was committed to approximately $1.2 billion in such obligations under these contracts, which expire in various years from 2007 through 2025.

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 2006, PSCo purchased natural gas from approximately 37 suppliers.

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

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PSCo Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2006		2005		2004
Natural Gas Deliveries (Thousands of MMBtu)
Residential	87,200		91,086		88,726
Commercial and Industrial	37,923		38,475		38,501
Total Retail	125,123		129,561		127,227
Transportation and Other	121,501		118,214		102,139
Total Deliveries	246,624		247,775		229,366
Number of customers at end of period
Residential	1,154,598		1,130,888		1,111,377
Commercial and Industrial	96,787		95,302		94,414
Total Retail	1,251,385		1,226,190		1,205,791
Transportation and Other	3,945		3,728		3,506
Total Customers	1,255,330		1,229,918		1,209,297
Natural Gas Revenues (Thousands of Dollars)
Residential	$	866,176	$	924,030	$	742,724
Commercial and Industrial	342,404		356,374		288,002
Total Retail	1,208,580		1,280,404		1,030,726
Transportation and Other	53,715		48,630		43,263
Total Natural Gas Revenues	$	1,262,295	$	1,329,034	$	1,073,989
MMBtu Sales per Retail Customer	99.99		105.66		105.51
Revenue per Retail Customer	$	965.79	$	1,044.21	$	854.81
Residential Revenue per MMBtu	$	9.93	$	10.14	$	8.37
Commercial and Industrial Revenue per MMBtu	$	9.03	$	9.26	$	7.48
Transportation and Other Revenue per MMBtu	$	0.44	$	0.41	$	0.42

ENVIRONMENTAL MATTERS

Certain of 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. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

PSCo strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon PSCo’s operations. For more information on environmental contingencies, see Note 12 to the Consolidated Financial Statements and the matter discussed below.

Leyden Gas Storage Facility — In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (Leyden) after 40 years of operation.  In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known.  In 2003, PSCo began flooding the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo.  In August 2003, the Colorado Oil and Gas Conservation Commission (COGCC) approved the closure plan, the last formal regulatory approval necessary before conversion.  On Dec. 31, 2005, PSCo’s leases of the Leyden properties were terminated and the city of Arvada took custody of the facility.  PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2005, PSCo has incurred approximately $5.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs.  PSCo has accrued an additional $0.2 million of costs expected to be incurred through 2006 to complete the decommissioning and closure of the facility.  PSCo has deferred these costs as a regulatory asset..  In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of Leyden costs totaling $4.8 million to be amortized over four years.  PSCo has reached a settlement agreement with the parties in the case.  The CPUC approved the settlement agreement on Jan. 19, 2006, and the final order became effective on Feb. 3, 2006.  In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional Leyden costs, plus unrecovered amounts previously authorized from the last rate case, which amounted to $5.9 million to be amortized over four years.  The total amount PSCo is requesting be recovered from customers is $7.7 million.

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EMPLOYEES

The number of full-time PSCo employees on Dec. 31, 2006 was 2,589. Of these full-time employees, 2,146, or 83 percent, are covered under collective bargaining agreements. See Note 7 to the Consolidated Financial Statements for further discussion. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to PSCo.

Item 1A — Risk Factors

Risks Associated with Our Business

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

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

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

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations 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 paying 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 if, in its judgment, circumstances in the future so warrant.  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 and Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts.   An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard and Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings variability. We utilize quoted market prices to the maximum extent possible in determining the value of these derivative commodity instruments.  For positions for which market prices are not available, we utilize models based on forward price curves. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability.

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If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.

We are subject to interest rate risk.

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

We are subject to credit risks.

Credit risk includes the risk that 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.

We have received a notice from the IRS proposing to disallow certain interest expense deductions that we claimed in 1993 through 1999. Should the IRS ultimately prevail on this issue, our liquidity position and financial results could be materially adversely affected.

Our wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of our employees, known as COLI. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.

In April 2004, Xcel Energy filed a lawsuit against the U.S. government in the U.S. District Court for the District of Minnesota to establish its right to deduct the interest expense that had accrued during tax years 1993 and 1994 on policy loans related to the COLI policies.

After Xcel Energy filed this suit, the IRS sent two statutory notices of deficiency of tax, penalty and interest for 1995 through 1999. Xcel Energy has filed U.S. Tax Court petitions challenging those notices. Xcel Energy anticipates the dispute relating to its interest expense deductions will be resolved in the refund suit that is pending in the Minnesota Federal District Court and the Tax Court petitions will be held in abeyance pending the outcome of the refund litigation. In the third quarter of 2006, Xcel Energy also received a statutory notice of deficiency from the IRS for tax years 2000 through 2002 and timely filed a Tax Court petition challenging the denial of the COLI interest expense deductions for those years.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution. At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies. However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.

On May 5, 2006, Xcel Energy filed a second motion for summary judgment. On Aug. 18, 2006, the U.S. government filed a second motion for summary judgment.  On February 14, 2007 the Magistrate Judge issued his Report and Recommendation (R&R) to the Judge concerning both motions. In his R&R the Magistrate Judge recommends both motions be denied due to fact issues in dispute. Both parties will have an opportunity to file objections by March 5, 2007 to the Magistrate Judge’s recommendations. The Judge will then have broad authority to, among other things, accept or reject the recommendations in whole or in part.  If both sides’ motions are ultimately denied, a trial is set to begin on July 24, 2007.

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Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties, and has continued to take deductions for interest expense on policy loans on its income tax returns for subsequent years. The litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. The ultimate resolution of this matter is uncertain and could have a material adverse effect on our financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2006, would reduce earnings by an estimated $421 million. Xcel Energy has received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2006, is approximately $499 million. In addition, Our annual earnings for 2007 would be reduced by approximately $49 million, after tax, if COLI interest expense deductions were no longer available.

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

We are subject to a number of environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the management of wastes and hazardous substances.  These laws and regulations generally 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 must 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, 2006, these sites included:

·the sites of former manufactured gas plants operated by our subsidiaries or predecessors; and

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

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.  Revised or additional laws or regulations which result in increased compliance costs or additional operating restrictions, or currently unanticipated costs or restrictions under existing laws or regulations, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

For further discussion see Note 12 to the Consolidated Financial Statements.

Economic conditions could negatively impact our business.

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

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Our operations could be impacted by war, acts of terrorism or threats of terrorism.

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause disruptions of fuel supplies and markets, particularly with respect to natural gas and purchased energy.  War and the possibility of further war may have an adverse impact on the economy in general.

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

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

A disruption or black-out of the regional electric transmission grid could negatively impact our business.

Because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the Aug. 14, 2003 black-out in portions of the eastern U.S. and Canada.  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 of operations.

Reduced coal availability could negatively impact our business.

Our coal generation portfolio is heavily dependent on coal supplies located in the Powder River Basin of Wyoming.  Approximately 50 percent of PSCo annual coal requirement comes from this area. Coal generation comprises approximately 85 percent our annual generation.  We have recently experienced disruptions in the delivery of Powder River Basin coal to our facilities and such disruptions could occur again in the future.  Coal delivery may be subject to short-term interruptions or reductions due to various factors, including transportation problems, weather and availability of equipment.  Failure or delay by our suppliers of coal deliveries could disrupt our ability to deliver electricity and require us to incur additional expenses to meet the needs of our customers.  In addition, as agreements expire with our suppliers, we may not be able to enter into new agreements for coal delivery on equivalent terms.

Rising energy prices could negatively impact our business.

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

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

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, that could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.  The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.  For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

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Increased risks of regulatory penalties could negatively impact our business

The Energy Act increased FERC’s civil penalty authority for violation of FERC statutes, rules and orders.  FERC can now impose penalties of $1 million per violation per day.  Effective June 1, 2007, approximately 80 electric reliability standards that were historically subject to voluntary compliance will become mandatory and subject to potential civil penalties for violations.  If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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

We have defined benefit and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on actual stock market performance, changes in interest rates and any 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 may change and our contributions could be required in the future.

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

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

As we are a subsidiary of Xcel Energy, if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternate sources of funds to meet our cash needs.

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

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

As of Dec. 31, 2006, Xcel Energy had approximately $6.4 billion of long-term debt and $1.0 billion of short-term debt or current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.  Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guarantees is based upon the net

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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, 2006, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.2 million and $17.5 million of exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2006, was approximately $118.6 million.  Xcel Energy’s total exposure under these indemnities cannot be determined at this time.  If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

Our 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 2006, 2005 and 2004 we paid $195.6 million, $62.6 million and $243.9 million of dividends to Xcel Energy, respectively.  If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved SEC Staff Comments

None.

Item 2 — Properties

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

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Electric utility generating stations:

			Summer 2006 Net
			Dependable
Station, City and Unit	Fuel	Installed	Capability (MW)
Steam:
Arapahoe-Denver, CO 2 Units	Coal	1950-1955	156
Cameo-Grand Junction, CO 2 Units	Coal	1957-1960	73
Cherokee-Denver, CO 4 Units	Coal	1957-1968	717
Comanche-Pueblo, CO 2 Units	Coal	1973-1975	660
Craig-Craig, CO 2 Units	Coal	1979-1980	83	(a)
Hayden-Hayden, CO 2 Units	Coal	1965-1976	237	(b)
Pawnee-Brush, CO	Coal	1981	505
Valmont-Boulder, CO	Coal	1964	186
Zuni-Denver, CO 2 Units	Natural Gas/Oil	1948-1954	107
Combustion Turbines:
Fort St. Vrain-Platteville, CO 4 Units	Natural Gas	1972-2001	690
Various Locations 6 Units	Natural Gas	Various	174
Hydro:
Various Locations 12 Units		Various	32
Cabin Creek-Georgetown, CO Pumped Storage		1967	210
Wind:
Ponnequin-Weld County, CO		1999-2001	—
Diesel Generators:
Cherokee-Denver, CO 2 Units		1967	6
		Total	3,836

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

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2006:

Conductor Miles
345 KV	957
230 KV	10,787
138 KV	92
115 KV	4,851
Less than 115 KV	71,174

PSCo had 209 electric utility transmission and distribution substations at Dec. 31, 2006.

Natural gas utility mains at Dec. 31, 2006:

Miles
Transmission	2,303
Distribution	20,599

Item 3 — Legal Proceedings

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

For a discussion of legal claims and environmental proceedings, see Note 12 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending and Recently Concluded Regulatory Proceedings under Item 1 and Note 11 to the Consolidated Financial Statements under Item 8, incorporated by reference.

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

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

PART II

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

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

PSCo had dividend restrictions imposed by its debt agreements and FERC rules.  PSCo’s credit agreement prohibits dividends or other similar distributions unless covenants relating to PSCo’s capitalization are met.  Dividends are also subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The dividends declared during 2006 and 2005 were as follows:

Quarter Ended
(Thousands of Dollars)
March 31, 2006		June 30, 2006		Sept. 30, 2006		Dec. 31, 2006
$	65,033	$	64,622	$	65,970	$	64,778
March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
$	—	$	—	$	—	$	—

Item 6 — Selected Financial Data

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

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

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

Forward Looking Information

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,”  “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions.  Actual results may vary materially.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of PSCo to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by PSCo; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership, structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of PSCo’s Form 10-K for the year ended Dec. 31, 2006.

22

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

Results Of Operations

PSCo’s net income was approximately $241.5 million for 2006, compared with approximately $211.4 million for 2005.

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

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

PSCo has two distinct forms of wholesale sales: short-term wholesale and commodity trading.  Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for, and energy produced from, PSCo’s generation assets or the energy and capacity purchased to serve native load.  Commodity trading is not associated with PSCo’s generation assets or the energy and capacity purchased to serve native load.  Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Margins from commodity trading activity conducted at PSCo are partially redistributed to NSP-Minnesota and SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the JOA approved by the FERC.  Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue.  Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs.  Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:

	Base
	Electric			Short-Term			Commodity			Consolidated
(Millions of Dollars)	Utility			Wholesale			Trading			Totals
2006
Electric utility revenue (excluding commodity trading)	$	2,472		$	29		$	—		$	2,501
Fuel and purchased power	(1,465		)	(25		)	—			(1,490		)
Commodity trading revenue	—			—			466			466
Commodity trading costs	—			—			(461		)	(461		)
Gross margin before operating expenses	$	1,007		$	4		$	5		$	1,016
Margin as a percentage of revenue	40.7		%	13.8		%	1.1		%	34.2		%
2005
Electric utility revenue (excluding commodity trading)	$	2,486		$	17		$	—		$	2,503
Fuel and purchased power	(1,491		)	(16		)	—			(1,507		)
Commodity trading revenue	—			—			600			600
Commodity trading costs	—			—			(599		)	(599		)
Gross margin before operating expenses	$	995		$	1		$	1		$	997
Margin as a percentage of revenue	40.0		%	5.9		%	0.2		%	32.1		%

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

23

Base Electric Revenue

(Millions of Dollars)	2006 vs 2005
Sales growth	$	12
Non-fuel riders	11
Service quality adjustment	8
Gain on sale of SO2 allowances	4
Retail fuel cost recovery	(15		)
Firm wholesale revenue, including fuel	(13		)
Sales mix	(10		)
Capacity sales	(10		)
Other	(1		)
Total base electric revenue decrease	$	(14	)

Base Electric Margin

(Millions of Dollars)	2006 vs 2005
Fuel and purchased power cost recovery	$	21
Sales growth	12
Non-fuel riders	11
Service quality adjustment	8
Gain on sale of SO2 allowances	4
ECA incentive	(20		)
Fuel handling & procurement costs	(10		)
Capacity sales	(10		)
Sales mix and other	(4		)
Total base electric margin increase	$	12

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

(Millions of Dollars)	2006			2005
Natural gas utility revenue	$	1,262		$	1,329
Cost of natural gas purchased and transported	(938		)	(1,032		)
Natural gas utility margin	$	324		$	297

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

Natural Gas Revenue

(Millions of Dollars)	2006 vs 2005
Base rate change	$	18
Transportation	9
Sales growth (excluding weather impact)	2
Purchased gas adjustment clause recovery	(87		)
Other	(9		)
Total natural gas revenue decrease	$	(67	)

Natural Gas Margin

(Millions of Dollars)	2006 vs 2005
Base rate change	$	18
Transportation	8
Sales growth (excluding weather impact)	1
Estimated impact of weather	1
Other	(1		)
Total natural gas margin increase	$	27

24

Non-Fuel Operating Expense and Other Costs — Other operating and maintenance expenses for 2006 increased $22 million, or 4.1 percent, compared to 2005.  The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2006 vs 2005
Higher employee benefit costs	$	19
Higher plant costs	7
Higher materials costs	2
Higher uncollectible receivable costs	2
Higher transportation fleet costs	2
Lower consulting/contractor costs	(6		)
Gains/losses on sale or disposals of assets, net	(6		)
Other	2
Total non-fuel operating expense increase	$	22

Depreciation and amortization expense increased by approximately $1.5 million, or 0.6 percent, for 2006 compared with 2005, primarily due to plant additions and higher regulatory amortization of demand side management costs, offset by lower amortization related to Fort. St. Vrain which was fully amortized at the end of 2005.

Taxes (other than income taxes) decreased by approximately $2.6 million, or 2.8 percent, for 2006 compared with 2005, primarily due to lower property taxes relating to a change in 2005 valuation and the 2006 estimate.

Interest and other income (expense), net, decreased by approximately $2.3 million primarily due to higher interest expense on COLI loans, partially offset by higher interest income from the COLI life insurance investments.

Interest charges and financing costs decreased by approximately $7.3 million, or 5.1 percent, for 2006 compared with 2005, primarily due to the retirement of long-term debt in November 2005 and June 2006, partially offset with increased short-term borrowings.

AFDC is an amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers as the related property is depreciated.  Of this amount, debt related AFDC increased by approximately $8.8 million and equity related AFDC was consistent with 2005 levels.

Income tax expense increased by approximately $11.5 million in 2006, compared with 2005.  The increase was primarily due to higher pretax income.  The effective tax rate was 25.3 percent for 2006, compared with 24.9 percent for 2005.

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 that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  All financial and commodity related instruments, including derivatives, are subject to market risk.  These risks, as applicable to PSCo, are discussed in further detail below.

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

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

Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities”.

See Note 9 to the Consolidated Financial Statements for a discussion of the various trading and hedging contracts of PSCo.

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

25

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, with a given confidence interval under normal market conditions. PSCo utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.

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

	Year ended		During 2006
(Millions of Dollars)	Dec. 31, 2006		Average		High		Low
Commodity trading (a)	$	0.49	$	1.32	$	2.60	$	0.39

	Year ended		During 2005
(Millions of Dollars)	Dec. 31, 2005		Average		High		Low
Commodity trading (a)	$	2.06	$	1.44	$	4.43	$	0.26

(a)Comprises transactions for NSP-Minnesota, PSCo and SPS.

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

PSCo may engage in hedges of cash flow exposure.  The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income.  Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally offsets the change in the interest accrued on the underlying variable rate debt.  Hedges of fair value exposure are entered into to hedge the fair value of debt instruments.  Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of debt instruments.  To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis.  The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes.  There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2006 and 2005, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $3.2 million and $1.9 million, respectively.

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

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

Item 8 — Financial Statements and Supplementary Data

26

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 statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2006 and 2005, 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, 2006.  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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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.

As discussed in Note 7 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” as of December 31, 2006.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2007

27

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)

	Year Ended Dec. 31
	2006			2005			2004
Operating revenues
Electric utility	$	2,505,445		$	2,504,028		$	2,194,628
Natural gas utility	1,262,295			1,329,034			1,073,989
Steam and other	38,089			33,501			27,825
Total operating revenues	3,805,829			3,866,563			3,296,442
Operating expenses
Electric fuel and purchased power	1,489,714			1,507,248			1,242,684
Cost of natural gas sold and transported	938,380			1,032,504			785,055
Cost of sales — steam and other	21,043			19,231			17,383
Operating and maintenance expenses	569,059			546,608			510,157
Depreciation and amortization	239,916			238,402			223,442
Taxes (other than income taxes)	88,878			91,438			86,671
Total operating expenses	3,346,990			3,435,431			2,865,392
Operating income	458,839			431,132			431,050
Interest and other income (expense), net (see Note 8)	(14,223		)	(11,884		)	24
Allowance for funds used during construction - equity	2,650			2,655			9,809
Interest charges and financing costs
Interest charges — including financing costs of $6,029, $6,744, and $7,353, respectively	137,493			144,835			157,447
Allowance for funds used during construction - debt	(13,386		)	(4,589		)	(7,425		)
Total interest charges and financing costs	124,107			140,246			150,022
Income before income taxes	323,159			281,657			290,861
Income taxes	81,701			70,240			72,856
Net income	$	241,458		$	211,417		$	218,005

See Notes to Consolidated Financial Statements

28

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Year Ended Dec. 31
	2006			2005			2004
Operating activities
Net income	$	241,458		$	211,417		$	218,005
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	253,725			251,668			234,164
Deferred income taxes	76,040			111,455			79,493
Amortization of investment tax credits	(3,949		)	(3,971		)	(4,000		)
Allowance for equity funds used during construction	(2,650		)	(2,655		)	(9,809		)
Unrealized (gain) loss on derivative instruments	(136		)	(2,990		)	1,557
Change in accounts receivable	133,691			(137,782		)	(107,652		)
Change in accrued unbilled revenues	35,253			(61,760		)	(17,819		)
Change in inventories	34,865			(56,043		)	(31,781		)
Change in recoverable purchased natural gas and electric energy costs	72,566			(58,178		)	(27,068		)
Change in prepayments and other current assets	(27,728		)	17,773			(3,117		)
Change in accounts payable	(187,571		)	154,481			22,894
Change in other current liabilities	25,032			6,193			(5,222		)
Change in other noncurrent assets	(53,057		)	(43,506		)	32,226
Change in other noncurrent liabilities	(14,998		)	(309		)	(44,812		)
Net cash provided by operating activities	582,541			385,793			337,059
Investing activities
Capital/construction expenditures	(537,920		)	(424,292		)	(457,365		)
Proceeds from disposition of property, plant and equipment	—			—			11,682
Allowance for equity funds used during construction	2,650			2,655			9,809
Other investments	9,869			6,520			(1,691		)
Net cash used in investing activities	(525,401		)	(415,117		)	(437,565		)
Financing activities
Short-term borrowings — net	36,896			138,649			182,914
Proceeds from issuance of long-term debt	—			129,500			—
Borrowings under utility money pool arrangement	1,426,800			—			—
Repayments under utility money pool arrangement	(1,426,800		)	—			—
Borrowings under 5-year unsecured credit facility	—			293,000			—
Repayments under 5-year unsecured credit facility	—			(293,000		)	—
Repayment of long-term debt, including reacquisition premiums	(126,334		)	(375,354		)	(147,000		)
Capital contribution from parent	227,272			202,029			184,123
Dividends paid to parent	(195,625		)	(62,564		)	(243,906		)
Net cash provided by (used in) financing activities	(57,791		)	32,260			(23,869		)
Net increase (decrease) in cash and cash equivalents	(651		)	2,936			(124,375		)
Cash and cash equivalents at beginning of year	3,662			726			125,101
Cash and cash equivalents at end of year	$	3,011		$	3,662		$	726
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	125,284		$	139,414		$	151,424
Cash paid for income taxes (net of refunds received)	$	(6,640	)	$	(16,042	)	$	16,203
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	5,367		$	13,404		$	14,291

See Notes to Consolidated Financial Statements

29

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

	Dec. 31, 2006			Dec. 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	3,011		$	3,662
Accounts receivable — net of allowance for bad debts: $18,415 and $19,381, respectively	355,738			451,944
Accounts receivable from affiliates	8,621			47,746
Accrued unbilled revenues	199,361			234,614
Recoverable purchased natural gas and electric energy costs	157,827			230,393
Materials and supplies inventories — at average cost	43,029			42,602
Fuel inventory — at average cost	40,997			19,582
Natural gas inventory — at average cost	155,567			212,274
Derivative instruments valuation-at market	28,111			78,064
Deferred income taxes	62,791			19,781
Prepayments and other	14,654			15,437
Total current assets	1,069,707			1,356,099
Property, plant and equipment, at cost:
Electric utility plant	6,409,194			6,275,046
Natural gas utility plant	1,825,560			1,793,240
Common utility and other property	725,864			745,894
Construction work in progress	429,878			209,721
Total property, plant and equipment	9,390,496			9,023,901
Less accumulated depreciation	(2,912,233		)	(2,854,757		)
Net property, plant and equipment	6,478,263			6,169,144
Other assets:
Regulatory assets	589,016			231,801
Derivative instruments valuation-at market	161,502			164,251
Other investments	19,347			29,465
Other	45,784			35,191
Total other assets	815,649			460,708
Total assets	$	8,363,619		$	7,985,951
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	101,379		$	126,334
Short-term debt	372,500			335,604
Accounts payable	385,724			578,722
Accounts payable to affiliates	30,291			26,388
Taxes accrued	84,960			81,638
Dividends payable to parent	64,778			—
Derivative instruments valuation-at market	38,616			66,463
Accrued interest	35,362			36,498
Other	74,381			71,206
Total current liabilities	1,187,991			1,322,853
Deferred credits and other liabilities:
Deferred income taxes	1,004,027			811,961
Deferred investment tax credits	59,035			62,984
Regulatory liabilities	470,255			492,335
Pension and Employee Benefit Obligations	301,277			148,255
Customers advances for construction	279,011			288,397
Asset retirement obligations	43,335			41,968
Derivative instruments valuation-at market	156,623			170,849
Other liabilities	7,750			18,387
Total deferred credits and other liabilities	2,321,313			2,035,136
Commitments and contingent liabilities (see Note 12)
Capitalization (See Statements of Capitalization):
Long-term debt	1,845,278			1,945,973
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Additional paid in capital	2,411,204			2,183,932
Retained earnings	585,219			604,163
Accumulated other comprehensive income (loss)	12,614			(106,106		)
Total common stockholder’s equity	3,009,037			2,681,989
Total liabilities and equity	$	8,363,619		$	7,985,951

See Notes to Consolidated Financial Statements

30

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME

(Dollars in Thousands)

									Accumulated
									Other			Total
	Common Stock			Additional		Retained			Comprehensive			Stockholder’s
	Shares	Amount		Paid in Capital		Earnings			Income (loss)			Equity
Balance at Dec. 31, 2003	100	$	—	$	1,797,780	$	421,614		$	(79,426	)	$	2,139,968
Net income						218,005						218,005
Minimum pension liability adjustment, net of tax of $(4,202) (see Note 7)									(7,317		)	(7,317		)
Net derivative instrument fair value changes during the period, net of tax of $(947)									(1,475		)	(1,475		)
Unrealized gain — marketable securities, net of tax of $74									121			121
Comprehensive income for 2004												209,334
Common dividends declared to parent						(246,873		)				(246,873		)
Contribution of capital by parent				184,123								184,123
Balance at Dec. 31, 2004	100	$	—	$	1,981,903	$	392,746		$	(88,097	)	$	2,286,552
Net income						211,417						211,417
Minimum pension liability adjustment, net of tax of $(9,898) (see Note 7)									(16,644		)	(16,644		)
Net derivative instrument fair value changes during the period, net of tax of $(936)									(1,482		)	(1,482		)
Unrealized gain — marketable securities, net of tax of $71									117			117
Comprehensive income for 2005												193,408
Contribution of capital by parent				202,029								202,029
Balance at Dec. 31, 2005	100	$	—	$	2,183,932	$	604,163		$	(106,106	)	$	2,681,989
Net income						241,458						241,458
Minimum pension liability adjustment, net of tax of $19,239 (see Note 7)									31,589			31,589
Net derivative instrument fair value changes during the period, net of tax of $(981)									(1,607		)	(1,607		)
Unrealized loss — marketable securities, net of tax of $(46)									(75		)	(75		)
Comprehensive income for 2006												271,365
SFAS No. 158 adoption, net of tax of $53,995									88,813			88,813
Common dividends declared to parent						(260,402		)				(260,402		)
Contribution of capital by parent				227,272								227,272
Balance at Dec. 31, 2006	100	$	—	$	2,411,204	$	585,219		$	12,614		$	3,009,037

See Notes to Consolidated Financial Statements

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PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Thousands of Dollars)

	Dec. 31
	2006			2005
Long-Term Debt
First Mortgage Bonds, Series due:
June 1, 2006, 7.125%	$	—		$	125,000
Oct. 1, 2008, 4.375%	300,000			300,000
Oct. 1, 2012, 7.875%	600,000			600,000
March 1, 2013, 4.875%	250,000			250,000
April 1, 2014, 5.5%	275,000			275,000
Sept. 1, 2017, 4.375% (a)	129,500			129,500
Jan. 1, 2019, 5.1% (a)	48,750			48,750
Unsecured Senior A Notes, due July 15, 2009, 6.875%	200,000			200,000
Secured Medium-Term Notes, due March 5, 2007, 7.11%	100,000			100,000
Capital lease obligations, 11.2% due in installments through 2028	46,247			47,581
Unamortized discount	(2,840		)	(3,524		)
Total	1,946,657			2,072,307
Less current maturities	101,379			126,334
Total long-term debt	$	1,845,278		$	1,945,973
Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2006 and 2005	$	—		$	—
Additional paid in capital	2,411,204			2,183,932
Retained earnings	585,219			604,163
Accumulated other comprehensive income (loss)	12,614			(106,106		)
Total common stockholder’s equity	$	3,009,037		$	2,681,989

(a)Pollution control financing.

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — PSCo is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. PSCo is subject to the regulatory of the FERC and state utility commissions. 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 aspects.

Principles of Consolidation — PSCo has subsidiaries, which have been consolidated and for which all significant 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 meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.

PSCo has various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, PSCo presents its revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

·PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA.  The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The current ECA mechanism expired Dec. 31, 2006.  Effective Jan. 1, 2007 the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy.  The total incentive payment to PSCo in any calendar year will not exceed $11.25 million.  The ECA mechanism will be revised quarterly and interest will accrue monthly on the average deferred balance.  The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

·In Colorado, PSCo operates under an annual earnings test in which earnings above the authorized return on equity are refunded to customers.  PSCo operates under various service quality standards, which could require customer refunds if certain criteria are not met. PSCo’s rates also include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.  PSCo is allowed to recover certain costs associated with renewable energy resources through a specific retail rate rider.

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

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

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with SFAS 133. In addition, commodity trading results include the impacts of all pertinent margin-sharing mechanisms. For more information, see Note 9 to the Consolidated Financial Statements.

Derivative Financial Instruments — PSCo utilizes a variety of derivatives, including commodity forwards, futures and options, index or fixed price swaps and basis swaps, to mitigate market risks and to enhance its operations.  For further discussion of PSCo’s risk management and derivative activities see Note 9 to the Consolidated Financial Statements.

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

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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 other property held for future use.

PSCo records depreciation expense related to its plant by using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a period basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2006, 2005 and 2004 was 2.6 percent, 2.6 percent and 2.5 percent, respectively.

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

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

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

Legal Costs — Legal costs are not accrued, but expensed as incurred.

Income Taxes — Xcel Energy and its utility subsidiaries, including PSCo, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss.  The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company in the consolidated federal or combined state returns. PSCo defers income taxes for all temporary differences between the book and tax bases of assets and liabilities. The tax rates used are those that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13 to the Consolidated Financial Statements. For more information on income taxes, see Note 6 to the Consolidated Financial Statements.

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, asset retirement obligations, 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 is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.

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

Inventory — All inventories are recorded at average cost.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:

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

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

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

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on PSCo’s results of operations in the period the write-off is recorded.  See more discussion of regulatory assets and liabilities at Note 13 to the Consolidated Financial Statements.

Deferred Financing Costs — Other assets include deferred financing costs, which are amortized over the remaining maturity periods of the related debt. PSCo’s deferred financing costs, net of amortization, at Dec. 31, 2006 and 2005 were $11.4 million and $13.5 million, respectively.

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of the allowance for uncollectibles.  PSCo establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the Federal EPA.  PSCo follows the inventory model for all allowances.  The sales of allowances are reported in the Operating Activities section of the Consolidated Statements of Cash Flows.  The net margin on sales of emission allowances is included in Operating Revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

FASB Interpretation No. 48 (FIN 48) — In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” FIN 48 prescribes how a company should recognize, measure, present and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle. Following implementation, the ongoing recognition of changes in the measurement of uncertain tax positions could be reflected as a component of income tax expense.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. PSCo has substantially completed its analysis and does not expect the cumulative effect of the adoption to be material.

Fair Value Measurements (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets.  Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. PSCo is evaluating the impact of SFAS No. 157 on its financial condition and results of operations and does not expect the impact of implementation to be material.

2. Short-Term Borrowings

Commercial Paper — At Dec. 31, 2006 and 2005, PSCo had commercial paper outstanding of approximately $372.5 million and $335.6 million, respectively.  The weighted average interest rates at Dec. 31, 2006 and 2005 were 5.43 percent and 4.48 percent, respectively.

Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals.  Approval was also granted by the FERC in a July 18, 2006 order.  The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company.  PSCo has approval to borrow up to $250 million under the arrangement.  PSCo had no borrowings or loans outstanding under the arrangement at Dec. 31, 2006.

3.Long-Term Debt

Effective Oct. 14, 2005, PSCo discharged its Indenture, in accordance with its terms, dated as of Dec. 1, 1939, as supplemented (1939 Indenture).  As a result, PSCo’s Indenture, dated as of Oct. 1, 1993, as supplemented (1993 Indenture), became the first lien on PSCo’s electric properties subject to certain permitted liens as provided in the 1993 Indenture.  PSCo’s outstanding first collateral trust bonds issued under the 1993 Indenture are no longer be secured by bonds issued under the 1939 Indenture and are first mortgage bonds entitled to the benefit of the lien on PSCo’s electric properties under the 1993 Indenture and have been renamed “first mortgage bonds” to reflect this status.

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Credit Facilities — At Dec. 31, 2006, PSCo had the following committed credit facility in effect, in millions of dollars:

Credit Facility	Credit Facility Borrowings		Available*		Term	Maturity
$700	$	—	$	321.5	Five year	December 2011

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

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  PSCo has the right to request an extension of the final maturity date by one year.  The maturity extension is subject to majority bank group approval.  The credit facility has one financial covenant requiring that PSCo’s debt to total capitalization ratio be less than or equal to 65 percent with which PSCo was in compliance at Dec. 31, 2006.  The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by PSCo’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.

As of Dec. 31, 2006, PSCo had no direct borrowings on this line of credit; however, this credit facility was used to provide back-up support for PSCo commercial paper and letters of credit.  Also, $6.0 million of letters of credit were outstanding at Dec. 31, 2006, as discussed in Note 10 to the Consolidated Financial Statements, of which approximately $6.0 million were outstanding under the above credit facility.

Maturities of long-term debt are:

(Millions of Dollars)
2007	$	101.4
2008	$	301.4
2009	$	201.5
2010	$	1.6
2011	$	1.6

4. Preferred Stock

PSCo has authorized the issuance of preferred stock.

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

5. Joint Plant Ownership

Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2006:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Hayden Unit 1	$	87,051	$	45,840	$	371	75.5
Hayden Unit 2	81,467		47,021		544		37.4
Hayden Common Facilities	28,270		6,343		—		53.1
Craig Units 1 and 2	52,872		27,061		316		9.7
Craig Common Facilities, Units 1, 2 and 3	31,888		10,158		323		6.5-9.7
Comanche Unit 3	—		—		215,557		66.7
Transmission and other facilities, including substations	139,725		49,846		488		11.6-68.1
Total	$	421,273	$	186,269	$	217,599

PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity.  PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  PSCo began major construction on a new jointly owned 750 MW coal-fired unit in Pueblo, Colo. in January 2006.  Major construction on the new unit, Comanche 3, is expected to be completed in the fall of 2009.  PSCo is the operating agent under the joint ownership agreement.  Each of the respective owners is responsible for funding its portion of the construction costs.  For Comanche unit 3, the ownership percentage for Xcel Energy decreased in May 2006 from 74.7 percent to 66.7 percent for the project life-to-date and going forward.

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6. Income Taxes

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

	2006		2005		2004
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	4.3		2.3		3.4
Regulatory differences — utility plant items	0.2		0.3		1.5
Life insurance policies	(10.6	)	(10.8	)	(9.4	)
Tax credits recognized	(2.0	)	(2.5	)	(2.1	)
Resolution of income tax audits	(1.1	)	0.5		(4.9	)
Other — net	(0.5	)	0.1		1.5
Effective income tax rate	25.3	%	24.9	%	25.0	%

Income taxes comprise the following expense (benefit) items for the years ending Dec. 31:

(Thousands of Dollars)	2006			2005			2004
Current federal tax expense	$	(2,691	)	$	(32,833	)	$	(2,866	)
Current state tax expense	12,301			(4,411		)	2,229
Current tax credits	—			—			(2,000		)
Deferred federal tax expense	71,756			102,132			67,700
Deferred state tax expense	6,807			12,512			11,793
Deferred tax credits	(2,523		)	(3,189		)	—
Deferred investment tax credits	(3,949		)	(3,971		)	(4,000		)
Total income tax expense	$	81,701		$	70,240		$	72,856

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

(Thousands of Dollars)	2006			2005
Deferred tax expense excluding items below	$	149,056		$	89,333
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(808		)	4,801
Tax expense (benefit) allocated to other comprehensive income and other	(72,208		)	17,321
Deferred tax expense	$	76,040		$	111,455

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

(Thousands of Dollars)	2006		2005
Deferred tax liabilities:
Differences between book and tax basis of property	$	995,760	$	912,876
Deferred costs	57,518		84,685
Regulatory assets	51,723		47,937
Employee benefits	20,907		20,356
Other comprehensive income	7,669		—
Other	4,088		12,143
Total deferred tax liabilities	$	1,137,665	$	1,077,997
Deferred tax assets:
Unbilled revenue	$	71,986	$	90,379
Other comprehensive income	—		64,538
Net operating loss carryforward	59,362		66,917
Deferred investment tax credits	22,242		23,680
Regulatory liabilities	13,626		13,479
Other	29,213		26,824
Total deferred tax assets	$	196,429	$	285,817
Net deferred tax liability	$	941,236	$	792,180

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7. Benefit Plans and Other Postretirement Benefits

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

Xcel Energy offers various benefit plans to its benefit employees, including those of PSCo. Approximately 56 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2006, PSCo had 2,165 bargaining employees covered under a collective-bargaining agreement, which expires in May 2009.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income.  The following table shows the impact of the implementation on the consolidated statement of financial position.  PSCo applied regulatory accounting treatment, which allowed recognition of this item as a regulatory asset rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates.  The table reflects the deferral of these amounts as regulatory assets.  This table also includes noncontributory, defined benefit supplemental retirement income plans.

Balance Sheet Line	Pre-SFAS  No. 158			SFAS No. 158  Adjustment			SFAS No. 71  Adjustment		After SFAS  No. 158
Regulatory assets	$	226,013		$	—		$	363,003	$	589,016
Other (long-term assets)	48,417			(2,633		)	—		45,784
Prepayments and other (current deferred taxes)	14,339			315			—		14,654
Total Assets	$	288,769		$	(2,318	)	$	363,003	$	649,454
Other (current liabilities)	$	73,549		$	832		$	—	$	74,381
Pension and employee benefit obligations	84,547			216,730			—		301,277
Deferred income taxes	949,717			(82,939		)	137,249		1,004,027
Total Liabilities	$	1,107,813		$	134,623		$	137,249	$	1,379,685
AOCI-net of tax	$	(76,199	)	$	(136,941	)	$	225,754	$	12,614
Total Equity	$	(76,199	)	$	(136,941	)	$	225,754	$	12,614

Pension Benefits

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

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments and 20 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.

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

	2006		2005
Equity securities	63	%	65	%
Debt securities	22		20
Real estate	4		4
Cash	2		1
Nontraditional investments	9		10
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 11.3 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments that can provide a higher-than-average return.  A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2006, 2005 and 2004 exceeded the assumed level of 8.75, 8.75 and 9.0 percent, respectively.  Xcel Energy continually reviews its pension assumptions.  In 2007, Xcel Energy will continue to use an investment-return assumption of 8.75 percent.

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

(Thousands of Dollars)	2006			2005
Accumulated Benefit Obligation at Dec. 31	$	2,486,370		$	2,642,177
Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,796,780		$	2,732,263
Service cost	61,627			60,461
Interest cost	155,413			160,985
Plan amendments	(16,569		)	300
Actuarial (gain) loss	(82,339		)	85,558
Benefit payments	(248,357		)	(242,787		)
Obligation at Dec. 31	$	2,666,555		$	2,796,780
Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,093,536		$	3,062,016
Actual return on plan assets	306,196			254,307
Employer contributions	32,000			20,000
Benefit payments	(248,357		)	(242,787		)
Fair value of plan assets at Dec. 31	$	3,183,375		$	3,093,536
Funded Status of Plans at Dec. 31
Funded status	$	516,820		$	296,756
Noncurrent assets	586,713			685,028
Noncurrent liabilities	(69,893		)	(90,595		)
Net pension amounts recognized on Consolidate Balance Sheets	$	516,820		$	594,433
PSCo Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	164,970		$	210,085
Prior service cost	24,387			26,057
Total	$	189,357		$	236,142
SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	189,357		N/A
Total	$	189,357		N/A
PSCo accrued benefit liability recorded	$	(68,513	)	$	(88,414	)
Measurement Date	Dec. 31, 2006			Dec. 31, 2005
Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	5.75		%
Expected average long-term increase in compensation level	4.00		%	3.50		%

During 2002, PSCo’s pension plans became underfunded, and at Dec. 31, 2006, had projected benefit obligations of $728.1 million, which exceeded plan assets of $658.2 million.  At Dec. 31, 2005, the projected benefit obligations of $739.5 million, exceeded plan assets of $609.8 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $1.9 billion on Dec. 31, 2006.

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Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2004 through 2006 for Xcel Energy’s pension plans, and are not expected to require cash funding in 2007. PSCo elected to make voluntary contributions to its pension plan for bargaining employees of $29 million, $15 million and $10 million in 2006, 2005 and 2004, respectively.  During 2007, Xcel Energy expects to voluntarily contribute approximately $20 million to the PSCo pension plan for bargaining employees.

Plan Changes — The Pension Protection Act of 2006 (PPA) was reflected effective December 31, 2006.  PPA requires a change in the conversion basis for lump-sum payments, three-year vesting for plans with account balance or pension equity benefits, as well as the repeal of the Economic Growth and Tax Relief Reconciliation Act of 2001 sunset provisions.  These changes are reflected as a plan amendment for purposes of SFAS No. 87.

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

(Thousands of Dollars)	2006			2005			2004
Service cost	$	61,627		$	60,461		$	58,150
Interest cost	155,413			160,985			165,361
Expected return on plan assets	(268,065		)	(280,064		)	(302,958		)
Settlement gain	—			—			(926		)
Amortization of transition asset	—			—			(7		)
Amortization of prior service cost	29,696			30,035			30,009
Amortization of net (gain) loss	17,353			6,819			(15,207		)
Net periodic pension credit under SFAS No. 87	$	(3,976	)	$	(21,764	)	$	(65,578	)
PSCo
Net periodic pension cost (credit)	$	18,666		$	14,252		$	7,141
Significant Assumptions Used to Measure Costs
Discount rate	5.75		%	6.00		%	6.25		%
Expected average long-term increase in compensation level	3.50		%	3.50		%	3.50		%
Expected average long-term rate of return on assets	8.75		%	8.75		%	9.00		%

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 2007 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

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

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo  were approximately $6.2 million in 2006, $6.2 million in 2005 and $7.2 million in 2004.

Postretirement Health Care Benefits

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

In conjunction with the 1993 adoption of SFAS No. 106 — “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

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

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No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. In 2004, the investment strategy for the union asset fund was changed to increase the investment mix to equity funds. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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

	2006		2005
Equity and equity mutual fund securities	67	%	61	%
Fixed income/debt securities	21		17
Cash equivalents	11		21
Nontraditional Investments	1		1
	100	%	100	%

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

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

(Thousands of Dollars)	2006			2005
Change in Benefit Obligation
Obligation at Jan. 1	$	938,172		$	929,125
Service cost	6,633			6,684
Interest cost	52,939			55,060
Medicare subsidy reimbursements	3,561			—
Plan amendments	(945		)	—
Plan participants’ contributions	11,870			12,008
Actuarial gain	(27,511		)	(3,175		)
Benefit payments	(66,026		)	(61,530		)
Obligation at Dec. 31	$	918,693		$	938,172
Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	351,863		$	318,667
Actual return on plan assets	41,409			14,507
Plan participants’ contributions	11,870			12,008
Employer contributions	67,188			68,211
Benefit payments	(66,025		)	(61,530		)
Fair value of plan assets at Dec. 31	$	406,305		$	351,863
Funded Status at Dec. 31
Funded status	$	(512,388	)	$	(586,309	)
Current liabilities	(2,211		)	—
Noncurrent assets	—			15,736
Noncurrent liabilities	(510,177		)	(150,014		)
Net amounts recognized on Consolidated Balance Sheets	$	(512,388	)	$	(134,278	)

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PSCo Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss	$	106,450		$	164,158
Prior service cost (credit)	(2,613		)	(3,041		)
Transition obligation	66,809			77,813
Total	$	170,646		$	238,930
SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	170,646		N/A
Total	$	170,646		N/A
PSCo accrued benefit liability recorded	$	207,992		$	39,503
Measurement Date	Dec. 31, 2006			Dec. 31, 2005
Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	5.75		%

Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent.  The period until the ultimate rate is reached was also increased from two years to six years.  Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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

(Millions of Dollars)
1-percent increase in APBO components at Dec. 31, 2006	$59.7
1-percent decrease in APBO components at Dec. 31, 2006	(49.9	)
1-percent increase in service and interest components of the net periodic cost	4.9
1-percent decrease in service and interest components of the net periodic cost	(4.0	)

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

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $61 million during 2007.

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

(Thousands of Dollars)	2006			2005			2004
Service cost	$	6,633		$	6,684		$	6,100
Interest cost	52,939			55,060			52,604
Expected return on plan assets	(26,757		)	(25,700		)	(23,066		)
Amortization of transition obligation	14,444			14,578			14,578
Amortization of prior service credit	(2,178		)	(2,178		)	(2,179		)
Amortization of net loss	24,797			26,246			21,651
Net periodic postretirement benefit cost (credit) under SFAS No. 106	$	69,878		$	74,690		$	69,688

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PSCo
Net periodic postretirement benefit cost recognized — SFAS No. 106	39,976			43,841			42,248
Additional cost recognized due to effects of regulation	3,891			3,891			3,891
Net cost recognized for financial reporting	$	43,867		$	47,732		$	46,139
Significant assumptions used to measure costs (income)
Discount rate	5.75		%	6.00		%	6.25		%
Expected average long-term rate of return on assets (before tax)	7.5		%	5.5%-8.5		%	5.5%-8.5		%

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
2007	$	217,236	$	65,355	$	5,358	$	59,997
2008	215,815		67,110		5,755		61,355
2009	220,843		68,911		6,115		62,796
2010	227,528		70,457		6,430		64,027
2011	225,446		71,924		6,665		65,259
2012-2016	1,195,629		368,206		36,592		331,614

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8. Detail of Interest and Other Income (Expense) - Net

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consists of the following:

(Thousands of Dollars)	2006			2005			2004
Interest income	$	4,462		$	2,801		$	9,194
Other nonoperating income	2,581			3,621			8,346
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(20,404		)	(18,273		)	(17,075		)
Other nonoperating expense	(862		)	(33		)	(441		)
Total interest and other (expense) income — net	$	(14,223	)	$	(11,884	)	$	24

9. Derivative Instruments

In the normal course of business, PSCo is exposed to a variety of market risks.  Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  PSCo utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.  The use of these derivative instruments is discussed in further detail below.

Utility 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 both long- and short-term physical purchase and sales contracts for electric capacity, energy and other energy-related products, and for various fuels used in the generation of electricity and natural gas utility operations.  Commodity risk also is managed through the use of financial derivative instruments.  PSCo utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs.  In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost-recovery mechanism.  PSCo’s risk management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists.

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

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.

Types of and Accounting for Derivative Instruments

PSCo uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship.  The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance.  This classification is dependent on the applicability of specific regulation.  This includes certain instruments used to mitigate market risk for PSCo and all instruments related to the commodity trading operations.  The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective.  The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.  PSCo formally documents hedging relationships, including, 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 hedged transaction.  PSCo also formally assesses, both at inception and on a regular basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; and interest rate

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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 acquired to reduce commodity cost volatility.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge).  The types of qualifying hedging transactions that PSCo is currently engaged in are discussed below.

Cash Flow Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recorded as a component of Other Comprehensive Income or deferred as a regulatory asset or liability, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.  The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Commodity Cash Flow Hedges — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices.  These derivative instruments are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2006, PSCo had various commodity-related contracts classified as cash flow hedges extending through December 2009.  The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place.  Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale.

As of Dec. 31, 2006, PSCo had no amounts in Accumulated Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

PSCo had immaterial ineffectiveness related to commodity cash flow hedges during the year ended Dec. 31, 2006 and no ineffectiveness during the year ended Dec. 31, 2005.

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

As of Dec. 31, 2006, PSCo had net gains of approximately $1.5 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

PSCo had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2006 and 2005, respectively.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on PSCo’s Other Comprehensive Income, included in the Consolidated Statements of Stockholder’s Equity, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive loss related to hedges at Dec. 31, 2003	$	17.2
After-tax net unrealized gains related to derivative accounted for as hedges	8.6
After-tax net realized gains on derivative transactions reclassified into earnings	(10.1		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2004	$	15.7
After-tax net unrealized gains related to derivatives accounted for as hedges	11.9
After-tax net realized gains on derivative transactions reclassified into earnings	(13.4		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	14.2
After-tax net unrealized losses related to derivatives accounted for as hedges	(0.1		)
After-tax net realized gains on derivative transactions reclassified into earnings	(1.5		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006	$	12.6

Normal Purchases or Normal Sales Contracts

PSCo enters into contracts for the purchase and sale of commodities for use in its business operations.  SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.

PSCo evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133.  None of the contracts entered into within the commodity trading operations qualify for a normal designation.

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In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, PSCo began recording several long-term power purchase agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts will no longer be 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 balances.

Normal purchases and normal sales contracts are accounted for as executory contracts.

Commodity Trading Contracts - The fair value of commodity trading contracts as of Dec. 31, 2006 and 2005 was $(0.6) million and $2.1 million, respectively.

Hedging Contracts - The fair value of qualifying cash flow hedges at Dec. 31, 2006 and 2005 was $3.1 million and $1.0 million, respectively.

For a further discussion of other financial instruments at PSCo, see Note 10 to the Consolidated Financial Statements.

10. Financial Instruments

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

	2006				2005
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term investments	$	11,144	$	11,144	$	12,877	$	12,877
Long-term debt, including current portion	$	1,946,657	$	2,023,551	$	2,072,307	$	2,187,802

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 long-term investments are 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, 2006 and 2005. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit

PSCo use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Dec. 31, 2006, there was $6.0 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.

11. Rate Matters

Pending and Recently Concluded Regulatory Proceedings - FERC

FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of both PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a $1.6 million rate increase for PSCo, a formula transmission service rate for PSCo, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 kilovolt tie line costs in wholesale transmission service rates. On April 5, 2006, the FERC issued an order approving the uncontested settlement. PSCo placed the final rates in effect on June 1, 2006 and made refunds of approximately $3.7 million.

Pending and Recently Concluded Regulatory Proceedings - CPUC

Electric Rate Case — In April 2006, PSCo filed with the CPUC to increase electricity rates by $208 million annually, beginning Jan. 1, 2007.  The request was based on two components, including an increase in base rate revenues of $178 million and an estimated $30 million increase in PCCA revenue.  The base rate request was based on a return on equity of 11 percent, an equity ratio of 59.9 percent and an electric rate base of $3.4 billion.  No interim rate increase was implemented.  The PCCA request was based on 2007 projected costs.

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On Oct. 20, 2006, PSCo entered into a comprehensive settlement agreement with several of the parties to the case.  On Nov. 20, 2006, the CPUC issued a written order approving the settlement with new rates effective Jan. 1, 2007.   The settlement provides for an increase in base rates of $107 million, based on a 10.50 percent return on equity, an estimated $39.4 million in PCCA revenue and an estimated $4.6 million in ECA revenue to recover certain WindSource program costs for a total increase of $151 million.  In addition, PSCo is permitted an incentive for its performance on achieving fuel and purchased energy savings as well as for its generation based wholesale margins.

Natural Gas Rate Case— On Dec. 1, 2006, PSCo filed with the CPUC a request to increase natural gas rates by $41.5 million, annually, representing an overall increase of 2.96 percent.  The request is based on a requested capital structure of 60.17 percent common equity, a return on common equity of 11 percent and a rate base of approximately $1.1 billion.  It is anticipated that new rates will become effective in the third quarter of 2007.

Quality of Service Plan — The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2006, PSCo filed its calendar year 2005 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures.  PSCo did not achieve the 2005 performance targets for the electric service unavailability measure creating a bill credit obligation of $13.6 million.  Additionally, in accordance with a prior agreement, PSCo invested an additional $11 million in 2006 toward improving reliability.  As a result, PSCo will not be required to pay any bill credits that may be owed for 2006 performance results for electric service unavailability.    The maximum potential bill credit obligation for 2006 related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million.  PSCo does not anticipate any bill credits will be due customers based on the 2006 performance targets.

12. Commitments and Contingent Liabilities

Tax Matters - In April 2004, Xcel Energy filed a lawsuit against the U.S. government in the U.S. District Court for the District of Minnesota to establish its right to deduct the interest expense that had accrued during tax years 1993 and 1994 on policy loans related to the COLI policies.

After Xcel Energy filed this suit, the IRS sent two statutory notices of deficiency of tax, penalty and interest for 1995 through 1999. Xcel Energy has filed U.S. Tax Court petitions challenging those notices. Xcel Energy anticipates the dispute relating to its interest expense deductions will be resolved in the refund suit that is pending in the Minnesota Federal District Court and the Tax Court petitions will be held in abeyance pending the outcome of the refund litigation. In the third quarter of 2006, Xcel Energy also received a statutory notice of deficiency from the IRS for tax years 2000 through 2002 and timely filed a Tax Court petition challenging the denial of the COLI interest expense deductions for those years.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution. At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies. However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.

On May 5, 2006, Xcel Energy filed a second motion for summary judgment. On Aug. 18, 2006, the U.S. government filed a second motion for summary judgment.  On Feb. 14, 2007, the Magistrate Judge issued his Report and Recommendation (R&R) to the Judge concerning both motions. In his R&R the Magistrate Judge recommends both motions be denied due to fact issues in dispute. Both parties will have an opportunity to file objections by March 5, 2007 to the Magistrate Judge’s recommendations. The Judge will then have broad authority to, among other things, accept or reject the recommendations in whole or in part.  If both sides’ motions are ultimately denied, a trial is set to begin on July 24, 2007.

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties, and has continued to take deductions for interest expense on policy loans on its income tax returns for subsequent years. The litigation could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. The ultimate resolution of this matter is uncertain and could have a material adverse effect on PSCo’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2006, would reduce earnings by an estimated $421 million. Xcel Energy has received formal notification that the IRS will seek penalties. If penalties (plus

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associated interest) also are included, the total exposure through Dec. 31, 2006, is approximately $499 million. In addition, PSCo’s annual earnings for 2007 would be reduced by approximately $49 million, after tax, if COLI interest expense deductions were no longer available.

COLI Dow Chemical Court Decision - On Jan. 23, 2006, the 6th Circuit of the U.S. Court of Appeals issued an opinion in a federal income tax case involving the interest deductions for a COLI program at Dow Chemical Company.  The 6th Circuit denied the tax deductions and reversed the decision of the trial court in the case.

Xcel Energy has analyzed the impact of the Dow decision on its pending COLI litigation and concluded there are significant factual differences between its case and the Dow case.  The court’s opinion in the Dow case outlined three indicators of potential economic benefits to be examined in a COLI case and noted that the outcome of COLI cases is very fact determinative.  These indicators are:

·Positive pre-deduction cash flows;

·Mortality gains; and

·The buildup of cash values.

In a split decision, the 6th Circuit found that the Dow COLI plans possessed none of these indicators of economic substance.  However, in Xcel Energy’s COLI case, the plans were projected to have sizeable pre-deduction cash flows, based upon the relevant assumptions when purchased.  Moreover, the plans presented the opportunity for mortality gains that were not eliminated either retroactively or prospectively.  Xcel Energy’s COLI plans had no provision for giving back any mortality gains that it might realize. In addition, Xcel Energy’s plans had large cash value increases that were not encumbered by loans during the first seven years of the policies.  Consequently, Xcel Energy believes that the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strong merits.

Leases — PSCo leases a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2028.  The assets and liabilities acquired under capital leases are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators.

Following is a summary of property held under capital leases:

(Millions of Dollars)	2006			2005
Storage, leaseholds and rights	$	40.5		$	40.5
Gas pipeline	20.7			20.7
	61.2			61.2
Less: Accumulated amortization	(15.0		)	(13.6		)
Total property held under capital leases	$	46.2		$	47.6

The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, cars and power-operated equipment are accounted for as operating leases.  Rental expense under operating lease obligations was approximately $17.1 million, $19.6 million and $17.6 million for 2006, 2005 and 2004, respectively.

Future commitments under noncancellable operating and capital leases with terms in excess of one year are:

(Millions of Dollars)	Operating Leases		Capital Leases
2007	$	8.8	$	6.3
2008	$	8.2	6.1
2009	$	8.1	6.0
2010	$	8.0	5.8
2011	$	7.9	5.6
Thereafter	$	34.0	62.4
Total minimum obligation			$	92.2
Interest component of obligation			(46.0		)
Present value of minimum obligation			$	46.2

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Capital Commitments — The estimated cost, as of Dec. 31, 2006, of the capital expenditure programs and other capital requirements of PSCo was approximately $690 million in 2007, $635 million in 2008 and $515 million in 2009.  PSCo’s capital expenditure forecast includes the following major project:

Comanche 3 - Comanche 3, a 750-MW coal-fired plant being built in Colorado is expected to cost approximately $1.35 billion, with major construction initiated in 2006 and completed in the fall of 2009.  The CPUC has approved sharing one-third ownership of this plant with other parties.  Consequently, PSCo’s investment in Comanche 3 will be approximately $1 billion.

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

Fuel Contracts — PSCo has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2007 and 2025. 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.

The estimated minimum purchase obligation for PSCo under these contracts as of Dec. 31, 2006, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
		(Millions of Dollars)
$	632	$	766	$	730

Purchased Power Agreements — PSCo has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. PSCo has various pay-for-performance contracts with expiration dates through the year 2027. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices.  However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2006, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, were as follows (Millions of Dollars):

2007	$	410.1
2008	401.3
2009	411.9
2010	399.5
2011	392.1
2012 and thereafter	2,353.6
Total	$	4,368.5

Environmental Contingencies

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

Site Remediation — PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo and some other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including the following categories of sites:

·site of a former manufactured gas plant (MGP) operated by PSCo or its predecessors; and

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·third party sites, such as landfills, to which PSCo is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

PSCo records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received.  The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, assumptions are made where facts are not fully known. For instance,  assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known..  At Dec. 31, 2006, the liability for the cost of remediating these sites was estimated to be $1.3 million, of which $0.4 million was considered to be a current liability.  Some of the cost of remediation may be recovered from:

·insurance coverage;

·other parties that have contributed to the contamination; and

·customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for PSCo’s future costs for these sites.

Manufactured Gas Plant Site

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property.  An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River.  On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work.  PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring.  In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP site spent through March 2005, which amounted to $6.2 million, to be amortized over four years.  PSCo reached a settlement agreement with the parties in the case.  The CPUC approved the settlement agreement on Jan. 19, 2006 and the final order became effective on Feb. 3, 2006, with rates effective Feb. 6, 2006.  In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years.  The total amount PSCo is requesting be recovered from customers is $13.1 million.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases caused  MGP byproducts to migrate to the Cache La Poudre River, thereby substantially increasing the scope and cost of remediation.  PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River.  On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit.  On Jan. 3, 2006, Schrader filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and under the Resource Conservation and Recovery Act (RCRA).  Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA.  In September 2006, PSCo filed a Motion For Partial Summary Judgment to dismiss Schrader’s RCRA claim.  PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself.

Third Party and Other Environmental Site Remediation

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

Other Environmental Requirements

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit

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technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.  Some PSCo generating facilities will be subject to BART requirements.

The EPA requires states to develop implementation plans to comply with BART by December 2007. States are required to identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. On May 30, 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART technology or an approved BART alternative to make reasonable progress toward meeting the national visibility goal. On Aug. 1, 2006, PSCo submitted its BART alternatives analysis to the Colorado Air Pollution Control Division. As set forth in its analysis, PSCo estimates that implementation of the BART alternatives will cost approximately $211 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project, which are included in the capital budget. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2010 and 2012.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. PSCo continues to evaluate the strategy for complying with CAMR. Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both.  In February 2007, the Colorado Air Quality Control Commission passed a mercury rule.  The rule was based on a negotiated rule that was agreed upon by participating environmental groups, utilities, local government coalitions, and the Colorado Air Pollution Control Division. The rule requires controls to be installed at Pawnee Station in 2012 and all other Colorado units by 2014.  PSCo is evaluating the emission controls required to meet the new rule and is currently unable to provide a capital cost estimate

Federal Clean Water Act — The federal Clean Water Act requires EPA to regulate cooling water intake structures  to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking.  On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. It is unclear whether EPA will stay the deadlines in the rule until the remanded rulemaking is finished.  As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.

Notice of Violation — On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the Clean Air Act (CAA) at the Comanche and Pawnee plants 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. It 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 also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the CAA, the EPA met with PSCo in September 2002 to discuss the NOV.

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 SFAS No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143).  This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

Recorded Asset Retirement Obligations (ARO) — Asset retirement obligations have been recorded for steam production, electric transmission and distribution and natural gas distribution.  The steam production obligation includes asbestos and ash-containment facilities.  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.  Asset retirement obligations 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.

PSCo recognized an ARO for the retirement costs of its natural gas mains.  In addition, an ARO was recognized for the removal of electric, transmission and distribution equipment.  The electric transmission and distribution ARO consists of

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many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year.  Therefore, the obligation was measured using an average service life.

If PSCo had implemented FIN No. 47 at Jan. 1, 2005, the liability for asset retirement obligations would have increased by $12.1 million.

A reconciliation of the beginning and ending aggregate carrying amounts of PSCo’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2006  Dec. 31, 2005, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2006		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2006
Electric Utility Plant:
Steam production asbestos	$	9,099	$	—	$	—	$	535	$	—		$	9,634
Steam production ash containment	3,720		—		—		230		(44		)	3,906
Electric transmission and distribution	700		—		—		18		(125		)	593
Gas Utility Plant:
Gas transmission and distribution	28,449		—		—		706		47			29,202
Total liability	$	41,968	$	—	—		$	1,489	$	(122	)	$	43,335

(Thousands of Dollars)	Beginning Balance Jan. 1, 2005		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates		Ending Balance Dec. 31, 2005
Electric Utility Plant:
Steam production asbestos	$	—	$	1,462	$	—	$	7,637	$	—	$	9,099
Steam production ash containment	—		882		—		2,838		—		3,720
Electric transmission and distribution	—		700		—		—		—		700
Gas Utility Plant:
Gas transmission and distribution	—		28,449		—		—		—		28,449
Total liability	$	—	$	31,493	—		$	10,475	$	—	$	41,968

Indeterminate Asset Retirement Obligations — PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined.

Removal Costs - PSCo accrues an obligation for plant removal costs for generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.  These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2006 and Dec. 31, 2005 were $389 million and $377 million, respectively.

Legal Contingencies

In the normal course of business, PSCo is party to routine claims and litigation arising from prior and current operations. PSCo is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as

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several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although PSCo is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on PSCo. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

Payne et al. vs. PSCo et al. - In late October 2003, there was a wildfire in Boulder County, Colorado.  There was no loss of life, but there was property damage associated with this fire. On Oct. 28, 2005, an action against PSCo relating to this fire was filed in Boulder County District Court. There are 22 plaintiffs, including individuals, the City of Jamestown and two companies, and three co-defendants, including PSCo. Plaintiffs have asserted that a tree falling into PSCo distribution lines may have caused the fire. Discovery is nearly complete, and the case is set to go to trial commencing July 30, 2007. A motion for partial summary judgment has been filed by PSCo and its co-defendants.   PSCo is continuing to  vigorously defend itself against the claims asserted in this lawsuit . This lawsuit is not expected to have a material financial impact and PSCo believes that its insurance coverage will cover any liability in this matter.

Comanche 3 Permit Litigation - On Aug. 4, 2005, Citizens for Clean Air and Water in Pueblo and Southern Colorado and Clean Energy Action filed a complaint against the Colorado Air Pollution Control Division alleging that the Division improperly granted permits to PSCo under Colorado’s Prevention of Significant Deterioration program for the construction and operation of Comanche 3. PSCo intervened in the case.  On June 20, 2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits had been properly granted and plaintiffs’ claims to the contrary were without merit. Plaintiffs have appealed this decision.  On Nov. 22, 2006, plaintiffs filed their opening briefs. PSCo’s response was filed Dec. 26, 2006. The Colorado Court of Appeals is expected to rule on the appeal in 2007.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for the Southern District of Mississippi. Although PSCo is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on PSCo. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence, and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

Qwest vs. Xcel Energy Inc. - On June 24, 2004, an employee of PSCo was injured when a pole owned by Qwest malfunctioned.  The employee is seeking damages of approximately  $7 million. On Sept. 6, 2005, an action against Qwest relating to incident was filed in Denver District Court by the employee.  On April 18, 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo.  Pursuant to this agreement, Qwest has asserted that PSCo had an affirmative duty to properly train and instruct its employees on pole safety, including testing the pole for soundness before climbing.  PSCo filed a counterclaim on May 15, 2006, against Qwest asserting Qwest had a duty to PSCo and an obligation under the contract to maintain its poles in a safe and serviceable condition.  This case is still in the discovery phase and set for jury trial beginning May 14, 2007.

13. Regulatory Assets and Liabilities

PSCo’s financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or the business of PSCo no longer allow for the application of SFAS No. 71 under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in its statement of income.  The components of unamortized regulatory assets and liabilities on the balance sheets of PSCo are:

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	See	Remaining Amortization
(Thousands of Dollars)	Note	Period	2006		2005
Regulatory Assets:
Pension and employee benefit obligations	7	Various	$	386,346	$	27,234
Conservation programs (a)		Various	70,572		59,114
AFDC recorded in plant (a)		Plant lives	39,722		40,168
Contract valuation adjustments (b)	9	Term of related contract	39,131		58,214
Losses on reacquired debt	1	Term of related debt	24,315		26,228
Net asset retirement obligations		Plant lives	13,664		11,789
Environmental costs	11	Four years	8,522		—
Plant asset recovery (Pawnee II and Metro Ash)		Six months	2,452		7,355
Rate case costs	1	Various	2,190		1,699
Other		Various	2,102		—
Total regulatory assets			$	589,016	$	231,801
Regulatory Liabilities:
Plant removals costs	11		$	389,056	$	377,343
Investment tax credit deferrals			35,764		38,134
Contract valuation adjustments (b)	9		—		46,827
Deferred income tax adjustments			31,146		30,031
Renewable resource requirements			14,289		—
Total regulatory liabilities			$	470,255	$	492,335

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

(b)Includes the fair value of certain long-term contracts used to meet native energy requirements.

14. Segments and Related Information

PSCo has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility.

·PSCo’s Regulated Electric Utility 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 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.

To report net income for Regulated Electric and Regulated Natural Gas Utility segments, PSCo must assign or allocate all costs and certain other income. In general, costs are:

·directly assigned wherever applicable;

·allocated based on cost causation allocators wherever applicable; or

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

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

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			Regulated
	Regulated		Natural		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric Utility		Gas Utility		Other			Eliminations			Total
2006
Operating revenues from external customers	$	2,505,445	$	1,262,295	$	38,089		$	—		$	3,805,829
Intersegment revenues	201		90		—			(291		)	—
Total revenues	$	2,505,646	$	1,262,385	$	38,089		$	(291	)	$	3,805,829
Depreciation and amortization	$	177,329	$	56,054	$	6,533		$	—		$	239,916
Financing costs, mainly interest expense	95,674		26,984		1,750			(301		)	124,107
Income tax expense (benefit)	93,429		30,049		(41,777		)	—			81,701
Segment net income	$	170,997	$	57,475	$	12,986		$	—		$	241,458
2005
Operating revenues from external customers	$	2,504,028	$	1,329,034	$	33,501		$	—		$	3,866,563
Intersegment revenues	263		97		—			(360		)	—
Total revenues	$	2,504,291	$	1,329,131	$	33,501		(360		)	$	3,866,563
Depreciation and amortization	$	179,774	$	52,009	$	6,619		$	—		$	238,402
Financing costs, mainly interest expense	108,824		30,150		2,241			(969		)	140,246
Income tax expense (benefit)	89,579		23,112		(42,451		)	—			70,240
Segment net income	$	153,436	$	43,458	$	14,523		$	—		$	211,417
2004
Operating revenues from external customers	$	2,194,628	$	1,073,989	$	27,825		$	—		$	3,296,442
Intersegment revenues	180		69		—			(249		)	—
Total revenues	$	2,194,808	$	1,074,058	$	27,825		$	(249	)	$	3,296,442
Depreciation and amortization	$	170,337	$	47,167	$	5,938		$	—		$	223,442
Financing costs, mainly interest expense	116,686		32,033		2,409			(1,106		)	150,022
Income tax expense (benefit)	80,578		19,437		(27,159		)	—			72,856
Segment net income	$	152,870	$	58,513	$	6,622		$	—		$	218,005

15. 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 and received required FERC and state regulatory approvals.  See Note 2 for further discussion of this borrowing arrangement.

Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provides construction services to PSCo, for which it was paid $3.3 million in 2005 and $12.9 million in 2004.  UE was sold in April 2005.

Cheyenne Light, Fuel and Power (Cheyenne), a former Xcel Energy subsidiary, purchased all of its electricity requirements from PSCo. During 2004, Xcel Energy reached an agreement to sell Cheyenne.  The sale was completed in January 2005.

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

(Thousands of Dollars)	2006		2005		2004
Operating revenues:
Electric utility	$	—	$	2,378	$	48,666
Operating expenses:
Other operations — paid to Xcel Energy Services Inc	267,307		256,290		298,124
Interest expense	4,894		725		886

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

	2006				2005
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Minnesota	$	6,598	$	—	$	22,356	$	162
NSP-Wisconsin	1,285		—		—		2,281
SPS	—		1,189		86		—
Other subsidiaries of Xcel Energy Inc.	738		29,102		25,304		23,945
	$	8,621	$	30,291	$	47,746	$	26,388

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2006		June 30, 2006		Sept. 30, 2006		Dec. 31, 2006
Revenue	$	1,267,025	$	767,231	$	793,724	$	977,849
Operating income	133,087		105,348		99,504		120,900
Net income	76,846		52,193		47,358		65,061

	Quarter Ended
(Thousands of Dollars)	March 31, 2005		June 30, 2005		Sept. 30, 2005		Dec. 31, 2005
Revenue	$	1,039,277	$	783,208	$	782,723	$	1,261,355
Operating income	125,713		95,931		99,273		110,215
Net income	65,607		47,188		45,678		52,944

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

During 2005 and 2006, 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 Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that its disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during PSCo’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting.

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

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

Item 14 — Principal Accounting Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2007 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.Consolidated Financial Statements:

Reports of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2006, 2005 and 2004.

Consolidated Statements of Income — For the three years ended Dec. 31, 2006, 2005 and 2004.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2006, 2005 and 2004.

Consolidated Balance Sheets — As of Dec. 31, 2006 and 2005.

2.Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2006, 2005 and 2004.

3.Exhibits

	*Indicates incorporation by reference
	+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
2.01*	Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).
3.01*	Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*	By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*	Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
4.02*	Indentures supplemental to Indenture dated as of Oct. 1, 1993:

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

4.03*	Indenture dated July 1, 1999, between Public Service Co. of Colorado and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.04*	Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*	Registration Rights Agreement dated March 14, 2003 among Public Service Co. of Colorado , Bank One Capital Markets, Inc. and UBS Warburg LLC (Exhibit 4.1 to Form S-4 (file no. 333-106011) dated June 11, 2003).
4.06*	$700,000,000 Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 99.01 to Form 8-K (file no. 001-03280) dated Dec. 14, 2006).
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 Executive Annual Incentive Award Plan (Exhibit B to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.03*+	Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).

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10.04*+	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).
10.05*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).
10.06*+	Senior Executive Severance Policy, effective March 24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.07*+	New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998.
10.08*+	Directors’ Voluntary Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec 31, 1998).
10.09*+	Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.10*+	Salary Deferral and Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.11*+	Salary Deferral and Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.12*+	Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).
10.13*+	Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1995).
10.14*+	Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31, 1996).
10.15*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).
10.16*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).
10.17*+	Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.18*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.19*+	Xcel Energy 401(k) Savings Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.20*+	New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2004 but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.21*	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).
10.22*	Securities Litigation Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.23*	ERISA Actions Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.24*	Shareholder Derivative Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.25*+	Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.26*+	Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.01 to Xcel Energy Form 10-Q (file no. 001-03034) dated Sept. 30, 2005.
10.27*+	Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.28*+	Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.29*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.30*+	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).
10.31*+	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).
10.32*+	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).

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10.33*+	Xcel Energy Omnibus 2005 Incentive Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.34*+	Xcel Energy Executive Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.35*+	Xcel Energy Amended Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).
10.36*+	Xcel Energy Supplemental Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13, 2005).
10.37+	Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2006
10.38+	Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy
10.39*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between Public Service Co. of Colorado and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)).
10.40*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between Public Service Co. of Colorado and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)).
10.41*	Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.42*	Settlement Agreement among Public Service Co. of Colorado and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SCHEDULE II

PUBLIC SERVICE COMPANY OF COLORADO

VALUATION AND QUALIFYING ACCOUNTS

Years Ended Dec. 31, 2006, 2005 and 2004

(Thousands of Dollars)

			Additions
	Balance at		Charged		Charged		Deductions		Balance
	beginning		to costs &		to other		from		at end
	of period		expenses		accounts (1)		reserves (2)		of period
Reserve deducted from related assets:
Provision for uncollectible accounts:
2006	$	19,381	$	26,944	$	7,375	$	35,285	$	18,415
2005	$	14,734	$	24,214	$	6,216	$	25,783	$	19,381
2004	$	12,852	$	12,823	$	4,742	$	15,683	$	14,734

1)Recovery of amounts previously written off.

2)Principally uncollectible accounts written off or transferred.

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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/ BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

(Principal Financial Officer)

February 26, 2007

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/ PATRICIA K. VINCENT	/s/ GARY R. JOHNSON
Patricia K. Vincent	Gary R. Johnson
President, Chief Executive Officer and Director	Vice President, General Counsel and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ RICHARD C. KELLY
Teresa S. Madden	Richard C. Kelly
Vice President and Controller	Chairman and Director
(Principal Accounting Officer)
/s/ BENJAMIN G.S. FOWKE III	/s/ PAUL J. BONAVIA
Benjamin G.S. Fowke III	Paul J. Bonavia
Vice President, Chief Financial Officer and Director	Vice President and Director
(Principal Financial Officer)

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.

61