Xcel Energy 10K 2006 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 Dec. 31, 2006

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

Commission File Number 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

Minnesota		41-0448030
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
414 Nicollet Mall, Minneapolis, Minnesota		55401
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, including Area Code (612) 330-5500

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange on which Registered
Xcel Energy Inc.	Common Stock, $2.50 par value per share	New York
Xcel Energy Inc.	Rights to Purchase Common Stock, $2.50 par value per share Cumulative Preferred Stock, $100 par value:	New York
Xcel Energy Inc.	Preferred Stock $3.60 Cumulative	New York
Xcel Energy Inc.	Preferred Stock $4.08 Cumulative	New York
Xcel Energy Inc.	Preferred Stock $4.10 Cumulative	New York
Xcel Energy Inc.	Preferred Stock $4.11 Cumulative	New York
Xcel Energy Inc.	Preferred Stock $4.16 Cumulative	New York
Xcel Energy Inc.	Preferred Stock $4.56 Cumulative	New York

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

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

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 x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes or 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 registrants’ 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. o

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). x Large accelerated filer o Accelerated filer o Non-accelerated filer

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

As of June 30, 2006, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $7,843,601,587 and there were 405,560,301 shares of common stock outstanding.

As of February 20, 2007, there were 407,751,743 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2007 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

Index

Glossary of Terms
PART I	Item 1 —	Business	3
		COMPANY OVERVIEW	6
		ELECTRIC UTILITY OPERATIONS	8
		Electric Utility Trends	8
		NSP-Minnesota	9
		NSP-Wisconsin	15
		PSCo	15
		SPS	19
		Electric Operating Statistics	21
		NATURAL GAS UTILITY OPERATIONS	21
		Natural Gas Utility Trends	21
		NSP-Minnesota	21
		NSP-Wisconsin	23
		PSCo	24
		Natural Gas Operating Statistics	25
		ENVIRONMENTAL MATTERS	25
		CAPITAL SPENDING AND FINANCING	26
		EMPLOYEES	26
		EXECUTIVE OFFICERS	26
	Item 1A —	Risk Factors	27
	Item 1B —	Unresolved Staff Comments	32
	Item 2 —	Properties	32
	Item 3 —	Legal Proceedings	35
	Item 4 —	Submission of Matters to a Vote of Security Holders	38
PART II	Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
	Item 6 —	Selected Financial Data	40
	Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
	Item 7A —	Quantitative and Qualitative Disclosures about Market Risk	66
	Item 8 —	Financial Statements and Supplementary Data	66
	Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	F-57
	Item 9A —	Controls and Procedures	F-57
	Item 9B —	Other Information	F-58
PART III	Item 10 —	Directors, Executive Officers, and Corporate Governance	F-58
	Item 11 —	Executive Compensation	F-58
	Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	F-58
	Item 13 —	Certain Relationships, Related Transactions, and Director Independence	F-58
	Item 14 —	Principal Accounting Fees and Services	F-58
PART IV	Item 15 —	Exhibits, Financial Statement Schedules	F-59
SIGNATURES			F-70

PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

*Xcel Energy Subsidiaries and Affiliates (current and former)*
Cheyenne		Cheyenne Light, Fuel and Power Company, a Wyoming corporation
Eloigne		Eloigne Co., invests in rental housing projects that qualify for low-income housing tax credits
NRG		NRG Energy, Inc., a Delaware corporation and independent power producer
NMC		Nuclear Management Co., a company formed by NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corporation and Alliant Energy Corp.
NSP-Minnesota		Northern States Power Co., a Minnesota corporation
NSP-Wisconsin		Northern States Power Co., a Wisconsin corporation
Planergy		Planergy International, Inc., an energy management solutions company
PSCo		Public Service Company of Colorado, a Colorado corporation
PSRI		PSR Investments, Inc., a manager of permanent life insurance policies
SPS		Southwestern Public Service Co., a New Mexico corporation
UE		Utility Engineering Corporation, an engineering, construction and design company
Utility Subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
WGI		WestGas Interstate, Inc., a Colorado corporation operating an interstate natural gas pipeline
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.
DOE		United States Department of Energy
DOL		United States Department of Labor
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS		Internal Revenue Service
MPSC		Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
MPUC		Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NMPRC		New Mexico Public Regulation Commission. The state agency that regulates the retail rates and services and other aspects of SPS’ operations in New Mexico. The NMPRC also has jurisdiction over the issuance of securities by SPS.
NDPSC		North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.
NRC		Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
OCC		Colorado Office of Consumer Counsel.
PSCW		Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
PUCT		Public Utility Commission of Texas. The state agency that regulates the retail rates, services and other aspects of SPS’ operations in Texas.
SDPUC		South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
WDNR		Wisconsin Department of Natural Resources
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, weatherization and other programs to conserve or manage energy use by 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.
FCA		Fuel clause adjustment. A clause included in electric rate schedules that provides for monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
FCA (Wholesale)		Wholesale fuel clause adjustment. A fuel cost recovery mechanism in the NSP-Wisconsin, PSCo and SPS wholesale electric tariff that provides for monthly adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast for certain customers. The difference between the electric costs collected through the wholesale FCA tariff and the actual costs incurred in a month are collected or refunded in a subsequent period.
GCA		Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
PCCA		Purchased capacity cost adjustment. Allows PSCo to recover from 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 became effective Jan. 1, 2007, which 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.
PGA		Purchased gas adjustment. A clause included in NSP-Minnesota’s and NSP-Wisconsin’s retail natural gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas and natural gas transportation. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent period.
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 December 31, 2010. The QSP for the PSCo natural gas utility expires December 2007.
RCR		Renewable cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities and other costs incurred to facilitate the purchase of renewable energy (including wind energy) in retail electric rates in Minnesota. The RCR is revised annually. The RCR will be replaced by the TCR adjustment effective in 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.
TCR		Transmission cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota’s base electric rates in retail electric rates in Minnesota. The TCR was approved by the MPUC in 2006 to be effective in 2007, and will be revised annually as new transmission investments and costs are incurred.
*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
BART		Best Available Retrofit Technology
C20		Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133.
CAIR		Clean Air Interstate Rule

CAMR		Clean Air Mercury Rule
CAPCD		Colorado Air Pollution Control Division
COLI		Corporate-owned life insurance
decommissioning		The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
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.
EPS		Earnings per share of common stock outstanding
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).
JOA		Joint operating agreement among the utility subsidiaries
LIBOR		London Interbank Offered Rate
LNG		Liquefied natural gas. Natural gas that has been converted to a liquid.
mark-to-market		The process whereby an asset or liability is recognized at fair value.
MERP		Metropolitan Emissions Reduction Project
MGP		Manufactured gas plant
MISO		Midwest Independent Transmission System Operator, Inc.
Moody’s		Moody’s Investor Services Inc.
MPCA		Minnesota Pollution Control Agency
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 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.
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.
PFS		Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PJM		PJM Interconnection, LLC
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 the 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.
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS		Statement of Financial Accounting Standards
SO2		Sulfur dioxide
SPP		Southwest Power Pool, Inc.
Standard & Poor’s		Standard & Poor’s Ratings Services
TEMT		Transmission and Energy Markets Tariff
TCEQ		Texas Commission of Environmental Quality

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.
VaR		Value-at-risk
WDNR		Wisconsin Department of Natural Resources
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 (one KW equals one thousand watts)
Kwh		Kilowatt hours
Mcf		Thousand cubic feet
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.
Volt		The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts or KV.

COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2006, Xcel Energy’s continuing operations included the activity of four wholly-owned utility subsidiaries that serve electric and natural gas customers in 8 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.

Xcel Energy was incorporated under the laws of Minnesota in 1909. Xcel Energy’s executive offices are located at 414 Nicollet Mall, Minneapolis, Minn. 55401. Its Web site address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its Web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. In addition, the Xcel Energy Guidelines on Corporate Governance and Code of Conduct also are available on its Web site.

NSP-Minnesota

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately 13 percent of the total sales in 2006. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 90 percent of NSP-Minnesota’s retail electric operating revenues was derived from operations in Minnesota during 2006.

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the NSP System, including capital costs.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the NMC.

NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 245,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of NSP-Wisconsin’s total sales in 2006. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory to approximately 100,000 customers. See the discussion of the integrated management of the electric production and transmission system of NSP-Wisconsin under NSP-Minnesota, discussed previously. Approximately 97 percent of NSP-Wisconsin’s retail electric operating revenues was derived from operations in Wisconsin during 2006.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

PSCo

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 PSCo’s 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.

SPS

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. SPS serves approximately 386,000 electric customers in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 37 percent of SPS’ total Kwh sales in 2006. Approximately 77 percent of SPS’ retail electric operating revenues was derived from operations in Texas during 2006.

In October 2005, SPS reached a definitive agreement to sell its delivery system operations in Oklahoma, Kansas and a small portion of Texas to Tri-County Electric Cooperative. Effective July 31, 2006, SPS completed the sale to Tri-County Electric Cooperative for $24.5 million, and a gain of $6.1 million was recognized. SPS now provides wholesale service to Tri-County Electric Cooperative.

Other Subsidiaries

WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.

In 1999, WYCO Development LLC (WYCO) was jointly formed with a subsidiary of El Paso Corporation to develop and lease new natural gas pipeline and compression facilities. Xcel Energy plans to invest approximately $145 million in WYCO between 2007 and 2009. The WYCO pipeline project is expected to begin operations in 2008 and the WYCO storage project is expected to begin operations in 2009. The new pipeline and storage projects will be leased to Colorado Interstate Gas Company, a subsidiary of El Paso Corporation. The terms of the lease agreement of the new pipeline and storage projects will be based on FERC regulation and it is anticipated that they will be approved by the FERC as a component of the certificate filing to be made by the Colorado Interstate Gas Company.

Xcel Energy’s nonregulated subsidiary in continuing operations is Eloigne.

See financial information regarding the segments of Xcel Energy’s business at Note 17 to the Consolidated Financial Statements.

In the past, Xcel Energy had several other subsidiaries that were sold or divested. For more information regarding Xcel Energy’s discontinued operations, see Note 2 to the Consolidated Financial Statements.

ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

Utility Industry Growth — Xcel Energy 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. Xcel Energy has and plans to continue to file rate cases with state and federal regulators to earn a return on its investments and recover costs of operations. For more information regarding Xcel Energy’s capital expenditures, see Note 14 to the Consolidated Financial Statements.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change. Merger and acquisition activity was 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.

Xcel Energy recognizes that local market conditions and political realities must be considered in developing its transition to competition plan and a planned competition date for the Texas Panhandle. Given the current situation, Xcel Energy has been unable to develop a plan for the Texas Panhandle to move toward retail competition that would be in the best interests of its customers. Xcel Energy currently does not plan to propose to implement retail customer choice in the Texas Panhandle until required.

Xcel Energy does support the continued development of wholesale competition and non-discriminatory wholesale open access transmission services. Xcel Energy will continue to work with the SPP on RTO development for the Panhandle region and the incorporation of independent transmission operations to insure non-discriminatory open access. Xcel Energy is also still pursuing strengthening its transmission system internally to alleviate north and south congestion within the Texas Panhandle and other lines to increase the transfer capability between the Texas Panhandle and other electric systems.

Some states have implemented some form of retail electric utility competition. Much of Texas has implemented retail competition, but it is presently limited to utilities within the Electric Reliability Council of Texas (ERCOT), which does not include SPS. Under current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas. Xcel Energy does not plan to implement competition until it is required. In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.

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 each of Xcel Energy’s utility subsidiaries face these challenges, these subsidiaries believe their 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 electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries. State and local agencies have jurisdiction over many of Xcel Energy’s utility activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 13 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;

· 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 such as MISO; and

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

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

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. NSP-Minnesota and NSP-Wisconsin are members of the MISO. SPS is a member of the SPP. Each RTO separately files regional transmission tariff rates for approval by 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.

Centralized Regional Wholesale Markets — FERC rules require RTO’s to operate centralized regional wholesale energy markets. The FERC required the MISO to begin operation of a “Day 2” wholesale energy market on April 1, 2005. MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTRs. The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region, including the NSP-Minnesota and NSP-Wisconsin systems. SPP received FERC approval to initiate an Energy Imbalance Service (EIS) market, which will provide a more limited wholesale energy market that will affect the SPS system. The SPP EIS market commenced on Feb. 1, 2007.

NSP-Minnesota

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.

The MPUC is also empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received

authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA that provides for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers. With NSP-Minnesota’s participation in the MISO Day 2 market, questions were raised regarding the inclusion of certain MISO charges in the FCA. However, in December 2006, the MPUC authorized FCA recovery of all MISO Day 2 charges, except certain administrative charges, which NSP-Minnesota is partially recovering in base rates and partially deferring for future recovery. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

MERP Rider Regulation — In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress. The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs. At Dec. 31, 2006, the estimated ROE was 10.74 percent, based on construction progress to date.

Actual Costs as a Percent of Target Costs	ROE
Less than or equal to 75%		11.47	%
Over 75% and up through 85%		11.22	%
Over 85% and up through 95%		11.00	%
Over 95% and up through 105%		10.86	%
Over 105% and up through 115%		10.55	%
Over 115% and up through 125%		10.22	%
Over 125%		9.97	%

Capacity and Demand

Uninterrupted system peak demand for the NSP System’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
NSP System		8,665		9,212		9,787		9,623

The peak demand for the NSP System typically occurs in the summer. The 2006 system peak demand for the NSP System occurred on July 31, 2006.

Energy Sources and Related Initiatives

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

Purchased Power — NSP-Minnesota 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.

NSP-Minnesota 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.

Excelsior Energy Inc. (Excelsior) — In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration by the MPUC that NSP-Minnesota be compelled to enter into a power purchase agreement and purchase the output from each of two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota. Excelsior filed this petition making claims pursuant to Minnesota statutes, relating to Innovative Energy Project and Clean Energy Technology.

The MPUC referred this matter to a contested case hearing to develop the facts and issues that must be resolved to act on Excelsior’s petition, including development of price information. The contested case proceeding considered a 603 MW unit in phase I and a second 603 MW unit in phase II of Excelsior project.

In 2006, NSP-Minnesota and other parties filed testimony in phase I of this proceeding. The parties filed briefs in January 2007. The ALJ is expected to make a recommendation to the MPUC on phase I later in the first quarter of 2007 and make a recommendation on phase II in August 2007.

NSP-Minnesota’s position in the proceeding is that the proposal (i) is inconsistent with our resource need, (ii) is not likely to be least-cost and is not in the public interest, (iii) shifts substantial risks to NSP-Minnesota and our ratepayers, (iv) presents a power purchase agreement that is inconsistent with industry standards in its allocation of risks and costs, (v) the proposal fails to satisfy the elements of the statutes under which it is proposed, and (vi) the proposal could result in significant adverse financial consequences. NSP-Minnesota intends to request that all costs associated with the proposed power purchase agreement, if approved, will be recoverable in customer rates.

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period 2005 through 2019. The proposed plan identified needed resources and proposed processes for acquiring resources to meet those needs. On July 28, 2006, the MPUC issued an order that, among other things:

· Approved NSP-Minnesota’s proposal to proceed with a request for proposal for 136 MW of peaking resources with an intended in service date of 2011;

· Identified a base load resource need of 375 MW beginning in 2015 and required NSP-Minnesota to file a certificate of need application for a proposed base load resource to begin the acquisition process by Nov. 1, 2006;

· Approved acquisition of 1,680 MW of wind generation resource over the planning period;

· Accepted the proposed increases in demand-side management and energy-savings goals; and

· Accepted the submittal of Xcel’s plan for uprating the Monticello and Prairie Island nuclear plants along with a comprehensive environmental and upgrade plan for the Sherco plant.

On Oct. 18, 2006, the MPUC issued an order after reconsideration clarifying the Nov. 1, 2006, filing requirements and extending the filing requirement for the nuclear upgrades until Sept. 1, 2007, to accommodate scheduling and legislative review of the MPUC’s decision in the Monticello certificate of need proceeding.

NSP-Minnesota expects to file its next resource plan with the MPUC on July 1, 2007.

NSP-Minnesota Base Load Acquisition Proceeding — On Nov. 1, 2006, NSP-Minnesota filed a proposal with the MPUC for a purchase of 375 MW of capacity and energy from Manitoba Hydro for the period 2015-2025 and the purchase of 380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan. The proposal included a signed term sheet with Manitoba Hydro and a process to acquire the wind energy through competitive bidding. Alternative suppliers were entitled to submit competing proposals to the MPUC by Dec. 18, 2006. An alternate supplier proposed a 375 MW share of a mine mouth lignite circulating fluidized bed plant located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both components. The MPUC found both NSP-Minnesota’s proposal and the alternate proposal to be substantially complete and referred the matter to a contested case proceeding.

NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million. The MPUC granted a routing permit for the

first major transmission facilities in the development program in 2004. The remaining route permit proceedings were completed in 2005. In 2003, the MPUC also approved an RCR automatic adjustment mechanism that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments for delivery of renewable energy resources.

In late 2006, NSP-Minnesota filed two applications for certificates of need with the MPUC for four additional transmission lines in southwestern Minnesota and Chisago County. NSP-Minnesota along with ten other transmission providers, have announced plans to file certificate of need applications by mid 2007 for three transmission lines serving Minnesota and parts of surrounding states.

See Note 13 in the Consolidated Financial Statements for further discussion.

Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to the NSP System for native load customers.

Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 15 to the Consolidated Financial Statements.

Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive waste generated within its borders. Low-level radioactive waste from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of low-level waste) and at the Clive facility located in Utah (class A low-level substance only). NSP-Minnesota has an annual contract with Barnwell, but is also able to utilize the Clive facility through various low-level waste processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high level waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent Federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 15 to the Consolidated Financial Statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. In 2003, the Minnesota Legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at Prairie Island, for a total of 29 casks. In October 2006, the MPUC authorized an on-site storage facility and 30 casks at Monticello, which will allow the plant to operate to 2030. There decision becomes effective June 1, 2007, unless the legislature takes action. As of Dec. 31, 2006, there were 22 casks loaded and stored at the Prairie Island plant. See Note 15 in the Consolidated Financial Statements for further discussion of the matter.

PFS — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. On Feb. 28, 2006, the NRC commissioners issued the license for PFS, ending the 8-year effort to gain a license for the site. The license is contingent on the condition that PFS must demonstrate that it has adequate funding before construction may begin. In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the

storage and transportation of spent fuel to PFS. Also in December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel. In September 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous Conditional Approval of the site lease between PFS and the Skull Valley Indian tribe even though the conditions had been met. The stated reasons were principally lack of progress at Yucca Mountain and lack of Bureau of Indian Affairs staff to monitor this activity. Both findings are expected to be appealed.

Prairie Island Steam Generator Replacement — Prairie Island Unit 2 steam generators received required inspections during a scheduled 2005 outage. Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 regular refueling outage. Due to the potential shortages in the world markets for materials and shop capabilities, NSP-Minnesota received Xcel Energy board approval in August 2006 to begin the process for long-lead time materials.

NSP-Minnesota Nuclear Plant Re-licensing — Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. Monticello’s license renewal was approved by the NRC in November 2006, and the MPUC issued its approval in October 2006 allowing additional spent fuel storage. Minnesota statutes provide that the MPUC decision becomes effective June 1, 2007, which allows the legislature the opportunity to review the MPUC action if considered appropriate. Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and the MPUC, currently planned for submittal in early 2008.

Nuclear Plant Power Uprates — At the direction of the MPUC, NSP-Minnesota is pursuing capacity increases of all three units that will total approximately 250 MW, to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned for replacement during the refueling outage in 2013. Total capital investment for these activities is estimated to be approximately $1 billion between 2006 and 2015. NSP-Minnesota plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs. NSP-Minnesota plans to submit the certificate of need for the Monticello uprate in the second quarter of 2007 and the certificate of need for the Prairie Island uprate in the third quarter of 2007.

NMC — As of Dec. 31, 2006, all members of the NMC, other than Xcel Energy, have chosen to sell their units and exit the NMC. Regarding the remaining members of the NMC, the sales transaction of the CMS Energy Corp. Palisades Nuclear Power Plant is targeted to close in the first quarter of 2007. In December 2006, Wisconsin Electric Power Co., announced its intent to sell its Point Beach Nuclear Plant to FPL Energy, with the sale expected to close in the third or fourth quarter of 2007.

Following consummation of these sale transactions, NSP-Minnesota will be the sole remaining member of the NMC. NSP-Minnesota is evaluating the situation and is considering various alternatives, including transitioning the NMC to a wholly owned subsidiary of Xcel Energy. To facilitate implementation of this option, Xcel Energy plans are progressing to restructure the NMC to support a two-site organization, as well as reabsorb the administrative functions within Xcel Energy by the end of 2007.

For further discussion of nuclear obligations, see Note 15 to the Consolidated Financial Statements.

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.

NSP System	Coal*						Nuclear						Natural Gas						Average Fuel
Generating Plants	Cost			Percent			Cost			Percent			Cost			Percent			Cost
2006		$	1.12		59	%		$	0.46		38	%		$	7.28		3	%		$	1.08
2005		$	1.04		60	%		$	0.46		36	%		$	8.32		3	%		$	1.11
2004		$	0.99		61	%		$	0.44		37	%		$	6.48		2	%		$	0.92

* Includes refuse-derived fuel and wood

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

Fuel Sources — Coal inventory levels may vary widely among plants. However, the NSP System 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 NSP-Minnesota’s coal-fired plants. Estimated coal requirements at NSP-Minnesota and NSP-Wisconsin’s major coal-fired generating plants are approximately 12.4 million tons per year.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of approximately 99 percent of 2007 coal requirements, 99 percent of 2008 coal requirements and 99 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.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment with multiple producers and countries to alleviate the current supply/demand imbalance. Due to less availability in the world supply market for uranium, conversion and enrichment, NSP-Minnesota is working toward maintaining a strategic inventory level to decrease its exposure to supply limitations.

· Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2008, approximately 90 percent of the requirements for 2009 and approximately 32 percent of the requirements for 2010 through 2012 with no coverage of requirements for 2013 and beyond. Contracts with additional uranium concentrate suppliers are currently in various stages of negotiations that are expected to provide a portion of the requirements through 2016.

· Current contracts for conversion services cover 100 percent of the requirements through 2009 and approximately 67 percent of the requirements from 2010 through 2012, with no coverage for 2013 and beyond.

· Current enrichment services contracts cover 100 percent of 2007 and 2008, and approximately 96 percent of the 2009 requirements. Approximately 50 percent of the 2010 through 2013 enrichment services requirements are currently covered with no coverage of requirements for 2014 and beyond. These current contracts expire at varying times between 2009 and 2013. Contracts with additional enrichment services suppliers are being investigated for coverage from 2010 and beyond.

· Fuel fabrication for Monticello is covered through 2010. Under a new contract executed in 2006 for fuel fabrication services, Prairie Island’s fuel fabrication is 100 percent committed for six reloads with an option to extend for three additional reloads. The six reloads provide for fabrication services through at least 2013, while adding the optional reloads would provide for fabrication services to at least 2015.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium are currently being negotiated that would provide additional supply requirements through 2016. Some exposure to price volatility will remain, due to index-based pricing structures on the contracts.

The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for power plants are procured under short-, intermediate- and long-term contracts at liquid trading hubs that expire in various years from 2007 through 2027 in order to provide an adequate supply of fuel. 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, NSP-Minnesota’s commitments related to these contracts were approximately $128 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. NSP-Minnesota 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.

NSP-Wisconsin

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion).

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference of 2 percent above or below base rates, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. In 2006 only, the bandwidth was 2 percent above and 0.5 percent below base rates. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively. NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See discussion of the system capacity and demand under NSP-Minnesota Capacity and Demand discussed previously.

Energy Sources and Related Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See a discussion of the system energy sources under NSP-Minnesota Energy Sources and Related Initiatives discussed previously.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See a discussion of the system energy sources under NSP-Minnesota Fuel Supply and Costs discussed previously.

PSCo

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 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.

· 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.

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

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

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

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

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

Capacity and Demand

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 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 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 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 on-site 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 one percent rider that would apply to each customer’s total electric bill, providing 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

	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 Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

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 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 for 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.

SPS

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail operations as an electric utility and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have jurisdiction over SPS’ rates in those communities. The NMPRC also has jurisdiction over the issuance of securities. SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices, however, as discussed previously, SPS withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. The Texas retail fuel factors change each November and May based on the projected cost of natural gas.

If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased energy costs, if this condition is expected to continue.

PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities as it relates to fuel and purchased energy costs.

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC. The NMPRC authorized SPS to implement a monthly adjustment factor.

SPS recovers fuel and purchased energy costs from its wholesale customers through a wholesale fuel and purchased economic energy cost adjustment clause (FCAC) accepted for filing by the FERC.

Capacity and Demand

Uninterrupted system peak demand for SPS 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 (a)
SPS		4,679		4,667		4,711		4,722

The peak demand for the SPS system typically occurs in the summer. The 2006 system peak demand for SPS occurred on July 20, 2006.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, purchases from other utilities, independent power producers and power marketers, and demand-side management options to meet its net dependable system capacity requirements.

Purchased Power — SPS 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.

SPS 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.

SPS Resource Planning — In June 2006, NMPRC initiated a series of workshops for the purpose of drafting rules for integrated resource planning. In August 2006, workshop participants completed a consensus rule that was forwarded by the Hearing Examiner on Oct. 3, 2006, to the NMPRC for consideration. The proposed rules would apply to jurisdictional electric and gas utilities, such as SPS, that operate within the state. A final rule is expected to be adopted in early 2007.

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

All of the transmission arrangements for the SPS system are through FERC approved Open Access Transmission Tariffs (OATT). SPS also has several transmission arrangements through the SPP OATT. The SPP is a RTO that, among other things, administers an OATT for all its members. SPS’ entire service territory is within the SPP footprint, and SPS is a member of the SPP. The SPP owns no transmission facilities. Rather, the SPP is responsible for ensuring that transmission service across facilities owned by others, including SPS, is made available and used on a reliable and non-discriminatory basis. These OATTs contain policies and procedures for reliable use of the transmission systems for transmission, generation and load variations.

Fuel Supply and Costs

SPS Generating	Coal						Natural Gas						Average Fuel
Plants	Cost			Percent			Cost			Percent			Cost
2006		$	1.89		66	%		$	6.30		34	%		$	3.38
2005		$	1.32		68	%		$	7.77		32	%		$	3.38
2004		$	1.20		69	%		$	5.74		31	%		$	2.60

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

Fuel Sources — SPS purchases all of its coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to the plant bunkers. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to the plant bunkers to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires in 2016. For the Tolk station, the coal supply contract with TUCO expires in 2017. At Dec. 31, 2006, coal supplies at the Harrington and Tolk sites were approximately 37 and 37 days supply, respectively. TUCO has coal agreements to supply 100 percent of SPS’ coal requirements in 2007, 2008 and 2009 for the Harrington and Tolk stations. TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas suppliers for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel. These contracts expire in various years from 2007 through 2011. 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, SPS’ commitments related to these contracts were approximately $30 million.

Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. SPS 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.

Xcel Energy Electric Operating Statistics

	Year Ended Dec. 31,
	2006				2005				2004
Electric Sales (Millions of Kwh)
Residential		24,153				23,930				22,828
Commercial and Industrial		61,314				60,049				58,192
Public Authorities and Other		1,118				1,091				1,133
Total Retail		86,585				85,070				82,153
Sales for Resale		23,960				22,194				22,521
Total Energy Sold		110,545				107,264				104,674
Number of Customers at End of Period
Residential		2,831,704				2,791,859				2,800,338
Commercial and Industrial		403,678				400,035				401,744
Public Authorities and Other		73,279				75,937				79,777
Total Retail		3,308,661				3,267,831				3,281,859
Wholesale		138				128				206
Total Customers		3,308,799				3,267,959				3,282,065
Electric Revenues (Thousands of Dollars)
Residential		$	2,149,978			$	2,048,100			$	1,791,606
Commercial and Industrial		4,014,809				3,733,648				3,203,629
Public Authorities and Other		118,660				110,895				106,657
Total Retail		6,283,447				5,892,643				5,101,892
Wholesale		1,141,248				1,193,762				1,011,210
Other Electric Revenues		183,323				157,232				112,143
Total Electric Revenues		$	7,608,018			$	7,243,637			$	6,225,245
Kwh Sales per Retail Customer		26,169				26,033				25,032
Revenue per Retail Customer		$	1,899.09			$	1,803.23			$	1,554.57
Residential Revenue per Kwh		8.90		¢		8.56		¢		7.85		¢
Commercial and Industrial Revenue per Kwh		6.55		¢		6.22		¢		5.51		¢
Wholesale Revenue per Kwh		4.76		¢		5.38		¢		4.49		¢

NATURAL GAS UTILITY OPERATIONS

Natural Gas Utility Trends

The most significant recent developments in the natural gas operations of the utility subsidiaries were 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 residential customer declined from 103 MMBtu per year to 82 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.

NSP-Minnesota

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs.

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 601,336 MMBtu for 2006, which occurred on Feb. 17, 2006.

NSP-Minnesota 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 526,013 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 30 percent of winter natural gas requirements and 37 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 34 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. The 2006-2007 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota 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, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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

2006	$	8.32
2005	$	8.90
2004	$	6.88

The cost of natural gas supply, transportation service and storage service is recovered through the PGA cost recovery mechanism.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2007 through 2027.

NSP-Minnesota 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, NSP-Minnesota was committed to approximately $722 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 25 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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

NSP-Wisconsin

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC.

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

Natural Gas Cost Recovery Mechanisms — NSP-Wisconsin has a retail PGA natural gas cost recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost recovery factor, which is based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 135,362 MMBtu for 2006, which occurred on Feb. 17, 2006.

NSP-Wisconsin 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 130,887 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 27 percent of winter natural gas requirements and 27 percent of peak day, firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2006-2007 supply plan was approved by the PSCW in October 2006.

Natural Gas Supply and Costs

NSP-Wisconsin 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, NSP-Wisconsin conducts natural gas price hedging activity that has been approved by the PSCW. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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

2006	$	8.42
2005	$	8.64
2004	$	7.00

The cost of natural gas supply, transportation service and storage service is recovered through various cost recovery adjustment mechanisms.

NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2007 through 2027.

NSP-Wisconsin 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, NSP-Wisconsin was committed to approximately $127 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 25 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

PSCo

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.

· 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.

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 of capacity for PSCo 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 under 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.

Xcel Energy Gas Operating Statistics

	Year Ended Dec. 31,
	2006		2005		2004
Gas Deliveries (Thousands of MMBtu)
Residential	126,846		135,794		134,512
Commercial and Industrial	81,107		83,667		86,053
Total Retail	207,953		219,461		220,565
Transportation and Other	135,708		134,061		116,593
Total Deliveries	343,661		353,522		337,158
Number of Customers at End of Period
Residential	1,669,747		1,636,652		1,612,047
Commercial and Industrial	147,614		145,067		145,153
Total Retail	1,817,361		1,781,719		1,757,200
Transportation and Other	3,981		3,764		3,544
Total Customers	1,821,342		1,785,483		1,760,744
Gas Revenues (Thousands of Dollars)
Residential	$	1,330,025	$	1,450,316	$	1,180,120
Commercial and Industrial	755,204		794,230		660,227
Total Retail	2,085,229		2,244,546		1,840,347
Transportation and Other	70,770		62,839		75,167
Total Gas Revenues	$	2,155,999	$	2,307,385	$	1,915,514
MMBtu Sales per Retail Customer	114.43		123.17		125.52
Revenue per Retail Customer	$	1,147.39	$	1,259.76	$	1,047.32
Residential Revenue per MMBtu	$	10.49	$	10.68	$	8.77
Commercial and Industrial Revenue per MMBtu	$	9.31	$	9.49	$	7.67
Transportation and Other Revenue per MMBtu	$	0.52	$	0.47	$	0.63

ENVIRONMENTAL MATTERS

Certain of Xcel Energy’s subsidiary 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. Xcel Energy 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.

Xcel Energy and its subsidiaries strive 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 Xcel Energy’s operations. For more information on environmental contingencies, see Notes 14 and 15 to the Consolidated Financial Statements, environmental matters in Management’s Discussion and Analysis under Item 7 and the matters 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 the Leyden costs totaling $4.8 million to be amortized over four years. Xcel Energy 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.

CAPITAL SPENDING AND FINANCING

For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.

EMPLOYEES

The number of full-time Xcel Energy employees in continuing operations at Dec. 31, 2006, is presented in the table below. Of the full-time employees listed below, 5,411 or 56 percent, are covered under collective bargaining agreements.

NSP-Minnesota*		2,595
NSP-Wisconsin		527
PSCo		2,589
SPS		1,072
Xcel Energy Services Inc.		2,949
Other subsidiaries		3
Total		9,735

* NSP-Minnesota full-time employees include 420 employees loaned to the NMC. In addition, the NMC has 651 full-time employees of its own.

EXECUTIVE OFFICERS

Richard C. Kelly, 60, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present; President, Xcel Energy Inc., October 2003 to present. Previously, Chief Operating Officer, Xcel Energy Inc., October 2003 to June 2005, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2002 to October 2003 and President — Enterprises Business Unit, Xcel Energy, August 2000 to August 2002.

Paul J. Bonavia, 55, President — Utilities Group, Xcel Energy Inc., November 2005 to present; Vice President, Xcel Energy Services Inc., September 2000 to present. Previously, President — Commercial Enterprises Business Unit, Xcel Energy, December 2003 to October 2005 and President — Energy Markets Business Unit, Xcel Energy, August 2000 to December 2003.

Benjamin G.S. Fowke III, 48, Chief Financial Officer, Xcel Energy Inc., October 2003 to present; Vice President, Xcel Energy Inc., November 2002 to present. Previously, Treasurer, Xcel Energy Inc., November 2002 to May 2004 and Vice President and Chief Financial Officer — Energy Markets Business Unit, Xcel Energy, August 2000 to November 2002.

David L. Eves 46, President and Director, SPS, December 2006 to present; Chief Executive Officer, SPS, August 2006 to present. Previously, Vice President of Resource Planning and Acquisition, Xcel Energy, November 2002 to July 2006 and Managing Director, Resource Planning and Acquisition, Xcel Energy, August 2000 to November 2002.

Raymond E. Gogel, 56, Vice President, Xcel Energy Services Inc., April 2002 to present; Vice President Customer and Enterprise Solutions Group, Chief Human Resource Officer and Chief Administrative Officer, November 2005 to present. Previously, Chief Information Officer, Xcel Energy Services Inc., April 2002 to February 2006; Vice President and Senior Client Services Principal, IBM Global Services, April 2001 to April 2002 and Senior Project Executive, IBM Global Services, April 1999 to April 2001.

Cathy J. Hart, 57, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, November 2005 to present.

Gary R. Johnson, 60, Vice President and General Counsel, Xcel Energy Inc., August 2000 to present.

Cynthia L. Lesher, 58, President of the Minnesota host committee for the Republican National Convention as a loaned executive to the convention organization, January 2007 to present. President and Chief Executive Officer, NSP-Minnesota, October 2005 to present. Previously, Chief Administrative Officer, Xcel Energy, August 2000 to October 2005 and Chief Human Resources Officer, Xcel Energy, July 2001 to October 2005.

Teresa S. Madden, 50, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance — Customer and Field Operations Business Unit, Xcel Energy, August 2003 to January 2004, Interim CFO, Rogue Wave Software, Inc., February 2003 to July 2003 and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

Michael L. Swenson, 56, President and Chief Executive Officer, NSP-Wisconsin, February 2002 to present. Previously, State Vice President for North Dakota and South Dakota, August 2000 to February 2002.

George E. Tyson II, 41, Vice President and Treasurer, Xcel Energy Inc., May 2004 to present. Previously, Managing Director and Assistant Treasurer, Xcel Energy, July 2003 to May 2004; Director of Origination — Energy Markets Business Unit, Xcel Energy, May 2002 to July 2003; Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

Patricia K. Vincent, 48, President and Chief Executive Officer, PSCo, October 2005 to present. Previously, President — Customer and Field Operations Business Unit, Xcel Energy, July 2003 to October 2005, President — Retail Business Unit, Xcel Energy, March 2001 to July 2003 and Vice President of Marketing and Sales, Xcel Energy Services Inc., August 2000 to March 2001.

David M. Wilks, 60, Vice President, Xcel Energy Services Inc., September 2000 to present; President — Energy Supply Group, Xcel Energy Inc., August 2000 to present.

David M. Sparby, 52, Executive Vice President and Director, Acting President and Chief Executive Officer, NSP-Minnesota, January 2007 to present; Previously, Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., September 2000 to January 2007.

No family relationships exist between any of the executive officers or directors.

Item 1A — Risk Factors

Risks Associated with Our Business

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

We are subject to comprehensive regulation by several federal and state utility regulatory agencies. The utility commissions in the states where our utility subsidiaries operate 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.

The profitability of our utility operations is dependent on our ability to recover costs related to providing energy and utility services to our customers. Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the utility’s expenses incurred in a test year. Thus, the rates a utility is allowed to charge may or may not match its 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 the costs of our utility subsidiaries 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 such costs. Rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their under-recovered fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers. If all of the costs of our utility subsidiaries are not recovered through customer rates, they could incur financial operating losses, which, over the long term, could jeopardize their ability to pay us dividends and 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 dividends on our common stock.

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 or our subsidiaries’ 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, Xcel Energy and its subsidiaries 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.

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.

Our subsidiary, PSCo, has received a notice from the IRS proposing to disallow certain interest expense deductions that PSCo claimed under a COLI policy. Should the IRS ultimately prevail on this issue, our liquidity position and financial results could be materially adversely affected.

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of PSCo’s 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 2003.

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 Xcel Energy’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 associated interest) also are included, the total exposure through Dec. 31, 2006, is approximately $499 million. In addition, Xcel Energy’s annual earnings for 2007 would be reduced by approximately $49 million, after tax, or 11 cents per share, 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 14 to the Consolidated Financial Statements.

Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.

NSP-Minnesota’s two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:

· the risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

· limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

· uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota’s nuclear plants.

If an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

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.

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, including our nuclear power plants under the NRC’s design basis threat requirements, 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 85 percent of our annual coal requirement comes from this area. Coal generation comprises approximately 60 percent to 85 percent of our annual generation for the operating utilities. 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 and natural gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

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

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems 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.

Increase risks of regulatory penalties

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.

Risks Associated with Our Holding Company Structure

We must rely on cash from our subsidiaries to make dividend payments.

We are a holding company and thus our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends, depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for that purpose or for dividends on our common stock, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and/or contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of equity ratios, working capital or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.

If our utility subsidiaries were to cease making dividend payments, it could adversely affect our ability to pay dividends on our common stock and preferred stock or otherwise meet our financial obligations.

Certain provisions of law, as well as provisions in our bylaws and shareholder rights plan, may make it more difficult for others to obtain control of us, even though some shareholders might consider this favorable.

We are a Minnesota corporation and certain anti-takeover provisions of Minnesota law apply to us and create various impediments to the acquisition of control of us or to the consummation of certain business combinations with us. In addition, our shareholder rights plan contains provisions, which may make it more difficult to effect certain business combinations with us without the approval of our board of directors. Finally, certain federal and state utility regulatory statutes may also make it difficult for another party to acquire a controlling interest in us. These provisions of law and of our corporate documents, individually or in the aggregate, could discourage a future takeover attempt which individual shareholders might deem to be in their best interests or in which shareholders would receive a premium for their shares over current prices.

Item 1B — Unresolved SEC Staff Comments

None.

Item 2 — Properties

Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin is subject to the lien of their first mortgage bond indentures. Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

NSP-Minnesota

Station, City and Unit	Fuel	Installed		Summer 2006 Net Dependable Capability (MW)
*Steam:*
Sherburne-Becker, MN
Unit 1	Coal		1976		697
Unit 2	Coal		1977		682
Unit 3	Coal		1987		504	(a)
Prairie Island-Welch, MN
Unit 1	Nuclear		1973		551
Unit 2	Nuclear		1974		545
Monticello-Monticello, MN	Nuclear		1971		572
King-Bayport, MN	Coal		1968		528
Black Dog-Burnsville, MN
2 Units	Coal/Natural Gas		1955-1960		282
2 Units	Natural Gas		2002		298
High Bridge-St. Paul, MN
2 Units	Coal		1956-1959		271
Riverside-Minneapolis, MN
2 Units	Coal		1964-1987		381
*Combustion Turbine:*
Angus Anson-Sioux Falls, SD
3 Units	Natural Gas		1994-2005		384
Inver Hills-Inver Grove Heights, MN
6 Units	Natural Gas		1972		350
Blue Lake-Shakopee, MN
6 Units	Natural Gas		1974-2005		490
Other	Various		Various		169
			Total		6,704

(a) Based on NSP-Minnesota’s ownership interest of 59 percent.

NSP-Wisconsin

Station, City and Unit	Fuel	Installed		Summer 2006 Net Dependable Capability (MW)
Combustion Turbine:
Flambeau Station-Park Falls, WI - 1 Unit	Natural Gas/Oil		1969		13
Wheaton-Eau Claire, WI - 6 Units	Natural Gas/Oil		1973		353
French Island-La Crosse, WI - 2 Units	Oil		1974		147
Steam:
Bay Front-Ashland, WI - 3 Units	Coal/Wood/Natural Gas		1945-1960		73
French Island-La Crosse, WI - 2 Units	Wood/RDF(a)		1940-1948		29
Hydro:
19 Plants			Various		254
			Total		869

(a) RDF is refuse-derived fuel, made from municipal solid waste.

PSCo

Station, City and Unit	Fuel		Installed		Summer 2006 Net Dependable 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.

SPS

Station, City and Unit	Fuel		Installed		Summer 2006 Net Dependable Capability (MW)
Steam:
Harrington-Amarillo, TX 3 Units		Coal		1976-1980		1,044
Tolk-Muleshoe, TX 2 Units		Coal		1982-1985		1,080
Jones-Lubbock, TX 2 Units		Natural Gas		1971-1974		486
Plant X-Earth, TX 4 Units		Natural Gas		1952-1964		442
Nichols-Amarillo, TX 3 Units		Natural Gas		1960-1968		457
Cunningham-Hobbs, NM 2 Units		Natural Gas		1957-1965		267
Maddox-Hobbs, NM		Natural Gas		1967		118
CZ-2-Pampa, TX		Purchased Steam		1979		26
Moore County-Amarillo, TX		Natural Gas		1954		48
Gas Turbine:
Carlsbad-Carlsbad, NM		Natural Gas		1968		11
CZ-1-Pampa, TX		Hot Nitrogen		1965		13
Maddox-Hobbs, NM		Natural Gas		1976		60
Riverview-Electric City, TX		Natural Gas		1973		23
Cunningham-Hobbs, NM 2 Units		Natural Gas		1998		218
Diesel:
Tucumcari-NM 6 Units				1941-1979		—
				Total		4,293

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

Conductor Miles	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
500 KV		2,917		—		—		—
345 KV		5,648		1,312		957		5,139
230 KV		1,827		—		10,787		9,420
161 KV		295		1,494		—		—
138 KV		—		—		92		—
115 KV		6,484		1,529		4,851		10,835
Less than 115 KV		81,274		31,698		71,174		22,429

Electric utility transmission and distribution substations at Dec. 31, 2006:

	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
Quantity		364		203		209		441

Gas utility mains at Dec. 31, 2006:

Miles	NSP-Minnesota		NSP-Wisconsin		PSCo		WGI
Transmission		120		—		2,303		12
Distribution		9,321		2,147		20,599		—

Item 3 — Legal Proceedings

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

Nuclear Waste Disposal Litigation — The federal government has the responsibility to dispose of domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act (the Act) requires the DOE to implement this disposal program. This includes the siting, licensing, construction and operation of a permanent repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances. The Act and contracts between the DOE and domestic utilities obligated the DOE to begin to dispose of these materials by Jan. 31, 1998. The federal government has designated the site as Yucca Mountain in Nevada. The nuclear waste disposal program has resulted in extensive litigation.

On June 8, 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages, past and as projected into the future, in excess of $1 billion for the DOE’s failure to meet the 1998 deadline. NSP-Minnesota has demanded damages consisting of the added costs of storage of spent nuclear fuel at the Prairie Island and Monticello nuclear generating plants, costs related to the Private Fuel Storage, LLC and certain costs relating to the 1994 and 2003 state legislation relating to the storage of spent nuclear fuel at Prairie Island. On July 31, 2001, the Court granted NSP-Minnesota’s motion for partial summary judgment on liability. A subsequent court decision determined that the utilities were precluded from making a claim for future damages, a utility could claim damages up to some point prior to the trial, and separate claims would have to be made in the future as damages accumulated. In response to this decision, NSP-Minnesota filed an amended complaint seeking damages through Dec. 31, 2004.

NSP-Minnesota currently claims total damages in excess of $100 million through Dec. 31, 2004 (damages after 2004 will be claimed in subsequent proceedings). A trial on the damages issue commenced on Oct. 24, 2006, and concluded on Dec. 11, 2006. NSP-Minnesota’s initial post-trial brief was filed pursuant to the court’s scheduling order on Feb. 9, 2007 and additional briefs and reply briefs are expected to be filed by April 30, 2007. Closing arguments are set for May 31, 2007.

On July 9, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to most of the NRC’s challenged repository licensing regulations, the congressional resolution approving Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the approval of the Yucca Mountain site. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal at Yucca Mountain and incorporated in the NRC regulations. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel. In July 2006 the Office of Civilian Radioactive Waste Management indicated that under the “best achievable repository construction schedule”, Yucca Mountain would be able to begin accepting spent nuclear fuel in March 2017.

Lamb County Electric Cooperative — On July 24, 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas, which appeal is currently pending. Oral arguments in the case were heard March 23, 2005. SPS is awaiting the Court of Appeals decision.

On Oct. 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers. The PUCT order of May 23, 2003, found that SPS was legally serving the disputed customers, thus collaterally determining the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.

Manufactured Gas Plant Insurance Coverage Litigation — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. Although the Wisconsin action has not been dismissed, the January 2007 trial date was adjourned and has not been rescheduled.

NSP-Wisconsin has entered into confidential settlements with St. Paul Mercury Insurance Company, St. Paul Fire and Marine Insurance Company and the Phoenix Insurance Company (“St. Paul Companies”), Associated Electric & Gas Insurance Services Limited, Fireman’s Fund Insurance Company, INSCO, Ltd. (on its own behalf and on behalf of the insurance companies subscribing per Britamco, Ltd.), Allstate Insurance Company and Compagnie Europeene D’ Assurances Industrielles S.A. and these insurers have been dismissed from the Minnesota and Wisconsin actions. These settlements are not expected to have a material effect on Xcel Energy’s financial results.

NSP-Wisconsin has reached settlements in principle with Admiral Insurance Company; certain underwriters at Lloyd’s, London and certain London Market Insurance Companies (“London Market Insurers”), General Reinsurance Corporation and First State and Twin City Fire Insurance Companies. These settlements are not expected to have a material effect on Xcel Energy’s financial results.

On Oct. 6, 2006, the trial court issued a memorandum and order on various summary judgment motions. The court ruled that Minnesota law on allocation applies and ordered dismissal, without prejudice, of 15 carriers whose coverage would not be triggered under such an allocation method. The court denied the insurers’ motions for summary judgment on the sudden and accidental and absolute pollution exclusions; late notice; legal expenses and costs; certain specific lost policies; and miscellaneous coverage issues under several individual policies. The court granted the motions of Fidelity and Casualty Insurance Company and Continental Insurance Company related to certain specific lost policies. On Oct. 13, 2006, the trial court denied NSP-Wisconsin’s request for leave to file a motion for reconsideration of the court’s allocation decision. The Nov. 6, 2006 trial date was also adjourned to allow for additional discovery and potential motions in light of the Minnesota Supreme Court’s recent allocation decision in Wooddale Builders, Inc. v. Maryland Casualty Company, 722 N. W.2d 283 (Minn. 2006). The trial has been set for a four-week period commencing on July 16, 2007.

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits are not expected to have a material effect on Xcel Energy’s financial results.

Polychlorinated Biphenyl (PCB) Storage and Disposal — In August 2004, Xcel Energy received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contended the fine for the alleged violation was approximately $1.2 million. Xcel Energy contested the fine and submitted a voluntary disclosure to the EPA. On April 17, 2006, SPS received a notice of determination from the EPA stating that the voluntary disclosure had been reviewed and that SPS had met all conditions of the EPA’s audit policy. Accordingly, the EPA will mitigate 100 percent of the gravity-based penalty for the disclosed violation, and no economic penalty will be assessed.

Cornerstone Propane Partners, L.P. et al. vs. e prime, inc. et al. — On Feb. 2, 2004, a purported class action complaint was filed in the U.S. District Court for the Southern District of New York against e prime and three other defendants by Cornerstone Propane Partners, L.P., Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas futures and/or options contracts during the period from Jan. 1, 2000, to Dec. 31, 2002. The complaint alleges that defendants manipulated the price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange Act. In February 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. In February 2004, defendants, including e prime, filed motions to dismiss. In September 2004, the U.S. District Court denied the motions to dismiss. On Jan. 25, 2005, plaintiffs filed a motion for class certification, which defendants opposed. On Sept. 30, 2005, the U.S. District Court granted plaintiffs’ motion for class certification. On Oct. 17, 2005, defendants filed a petition with the Second Circuit Court of Appeals challenging the class certification. On Dec. 5, 2005, e prime reached a tentative settlement with the plaintiffs that received final court approval in May 2006. The settlement was paid by e prime and it did not have a material financial impact on Xcel Energy.

Department of Labor Audit — In 2001, Xcel Energy received notice from the U.S. DOL Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it was prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998. The DOL has offered to conclude the audit if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million. On July 19, 2004, Xcel Energy formally responded with a letter to the DOL that asserted no fiduciary violations have occurred and extended an offer to meet to discuss the matter further. In 2005, and again in January 2006, the DOL submitted two additional requests for information related to the investigation, and Xcel Energy submitted timely responses to each request.

On June 12, 2006, the DOL issued a letter to the Xcel Energy Pension Trust Administration Committee indicating that, although there may have been a breach of the Committee’s fiduciary obligations under ERISA, the DOL will not pursue

any action against the Committee or the pension plan with respect to these alleged breaches due, in part, to the steps the Committee has taken in outsourcing certain investment management and administration functions to third parties.

NewMech vs. Northern States Power Company — On May 16, 2006, NewMech served and filed a complaint against NSP-Minnesota, Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering in the Minnesota State District Court, Sherburne County, alleging entitlement to payment in the amount of approximately $4.2 million for unpaid costs allegedly associated with construction work done by NewMech at NSP-Minnesota and SMMPA’s jointly owned Sherco 3 generating plant in 2005. NewMech had previously served a mechanic’s lien, and sought, through this action, foreclosure of the lien and sale of the property. NewMech additionally sought the claimed damages as a result of an alleged breach of contract by NSP-Minnesota. NSP-Minnesota, SMMPA and Benson filed answers denying NewMech’s allegations. Additionally, NSP-Minnesota and SMMPA counterclaimed for damages in excess of $7 million for breach of contract, delay in contract performance, misrepresentation and fraudulent inducement to enter into the contract and slander of title. A confidential settlement of the dispute was reached on Sept. 29, 2006 and it did not have a material financial impact on Xcel Energy.

Additional Information

For more discussion of legal claims and environmental proceedings, see Note 14 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates and other regulatory matters, see Pending and Recently Concluded Regulatory Proceedings under Item 1, Management’s Discussion and Analysis under Item 7, and Note 13 to the Consolidated Financial Statements under Item 8, incorporated by reference.

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

No issues were submitted for a vote during the fourth quarter of 2006.

PART II

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

Quarterly Stock Data

Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE). The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2006 and 2005 and the dividends declared per share during those quarters.

	High			Low			Dividends
2006
First Quarter		$	19.61		$	17.91		$	0.2150
Second Quarter		$	19.76		$	17.80		$	0.2225
Third Quarter		$	21.05		$	18.96		$	0.2225
Fourth Quarter		$	23.63		$	20.56		$	0.2225

	High			Low			Dividends
2005
First Quarter		$	18.41		$	16.50		$	0.2075
Second Quarter		$	19.65		$	16.83		$	0.2150
Third Quarter		$	20.19		$	18.44		$	0.2150
Fourth Quarter		$	19.83		$	17.81		$	0.2150

Book value per share at Dec. 31, 2006, was $14.28. The number of common shareholders of record as of Dec. 31, 2006 was 98,881.

Xcel Energy’s Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2006 and 2005, the payment of cash dividends on common stock was not restricted. For further discussion of Xcel Energy’s dividend policy, see Liquidity and Capital Resources under Item 7.

The following compares our cumulative total shareholder return on common stock with the cumulative total return of the Standard & Poor’s 500 Composite Stock Price Index, and the EEI Electrics Index over the last five fiscal years (assuming a $100 investment in each vehicle on December 31, 2001 and the reinvestment of all dividends).

The EEI Electrics Index currently includes 63 companies and is a broad measure of industry performance.

COMPARATIVE TOTAL RETURN

	2001		2002		2003		2004		2005		2006
Xcel Energy	$	100	$	43	$	69	$	77	$	82	$	100
EEI Electrics	$	100	$	85	$	105	$	129	$	150	$	181
S&P 500	$	100	$	77	$	97	$	106	$	109	$	124

See Item 12 for information concerning securities authorized for issuance under equity compensation plans.

Item 6 — Selected Financial Data

	2006				2005				2004				2003				2002
	(Millions of Dollars, Except Share and Per-Share Data)
Operating revenues		$	9,840			$	9,625			$	8,216			$	7,731			$	6,893
Operating expenses		$	8,663			$	8,533			$	7,140			$	6,607			$	5,717
Income from continuing operations		$	569			$	499			$	522			$	523			$	549
Net income (loss)		$	572			$	513			$	356			$	622			$	(2,218	)
Earnings available for common stock		$	568			$	509			$	352			$	618			$	(2,222	)
Average number of common shares outstanding (000’s)		405,689				402,330				399,456				398,765				382,051
Average number of common and potentially dilutive shares outstanding (000’s)(c)		429,605				425,671				423,334				418,912				384,646
Earnings per share from continuing operations — basic		$	1.39			$	1.23			$	1.30			$	1.30			$	1.43
Earnings per share from continuing operations — diluted		$	1.35			$	1.20			$	1.26			$	1.26			$	1.43
Earnings per share-basic		$	1.40			$	1.26			$	0.88			$	1.55			$	(5.82	)
Earnings per share-diluted(c)		$	1.36			$	1.23			$	0.87			$	1.50			$	(5.77	)
Dividends declared per share		$	0.88			$	0.85			$	0.81			$	0.75			$	1.13
Total assets		$	21,958			$	21,505			$	20,305			$	20,205			$	29,436
Long-term debt(b)		$	6,450			$	5,898			$	6,493			$	6,494			$	5,294
Book value per share		$	14.28			$	13.37			$	12.99			$	12.95			$	11.70
Return on average common equity		10.1		%		9.6		%		6.8		%		12.6		%		(41.0		)%
Ratio of earnings to fixed charges(a)		2.2				2.2				2.2				2.2				2.5

(a) Excludes undistributed equity income and includes allowance for funds used during construction.

(b) Long-term debt includes only debt of continuing operations.

(c) The 2002 average number of common and potentially dilutive shares has been restated to include the effect of dilutive securities, which were excluded in 2002 due to Xcel Energy’s loss from continuing operations. Including these securities would have been antidilutive, or would have reduced the reported loss per share. In 2002, the loss from continuing operations that was caused by NRG made some securities “antidilutive” or would have reduced the reported loss per share. In 2003, NRG’s results were reclassified to discontinued operations.

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

Business Segments and Organizational Overview

Continuing Operations

Xcel Energy is a public utility holding company. In 2006, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 8 states. These utility subsidiaries are NSP-Minnesota; NSP-Wisconsin; PSCo; and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline, these companies comprise the continuing regulated utility operations.

Xcel Energy’s nonregulated subsidiary reported in continuing operations is Eloigne, which invests in rental housing projects that qualify for low-income housing tax reported credits.

Discontinued Operations

See Note 2 to the Consolidated Financial Statements for discussion of discontinued operations.

Forward-Looking 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 Xcel Energy and its subsidiaries 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 Xcel Energy and its subsidiaries; 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 Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including “Risk Factors” in Item 1A of Xcel Energy’s Form 10-K for the year ended Dec. 31, 2006 and Exhibit 99.01 to Xcel Energy’s Form 10-K for the year ended Dec. 31, 2006.

Management’s Strategic Plan

Xcel Energy’s strategy, called Building the Core, is to invest in the core utility businesses and earn a reasonable return on invested capital. We’re a vertically integrated utility and intend to stay that way. Investments of approximately $9 billion are planned over the next five years in our core operations to grow our business in response to growing customer demand and environmental initiatives. The need for additional energy supply is expected throughout our service territory. Many of the states in which we operate are considering renewable portfolio standards, requiring incremental investment in wind generation and transmission facitlities. Additionally, we continue to focus on enhancing electric system reliability including making significant investments in transmission and distribution systems. These customer driven requirements create investment opportunities for us.

The strategy of Building the Core has three phases. The first phase is obtaining legislative and regulatory support for large investment initiatives prior to making the investment. To avoid excessive risk for the company, it is critical to reduce regulatory uncertainty before making large capital investments. We accomplished this for both the MERP in Minnesota and the Comanche 3 coal plant in Colorado. Transmission legislation has been passed in Minnesota, allowing that state’s regulatory commission to approve recovery for transmission investments without filing a general rate case. In Texas, the legislature authorized annual recovery for transmission infrastructure improvements. Both legislative initiatives support necessary new investment in our transmission system.

The second phase is making those investments. In a normal year, we spend approximately $1 billion on capital projects. In addition to a base level of capital investment, we expect to have significant investment opportunity. Among those opportunities are:

· approximately $1 billion through 2010 for MERP, a project to convert two aging coal-fired plants to natural gas plants and to install pollution control equipment at a third coal plant;

· approximately $1 billion through 2010 for Comanche 3, a project to build a coal plant in Colorado;

· a proposed $1 billion through 2015 to extend the lives and increase the output of our two nuclear plants, Monticello and Prairie Island;

· a proposed $900 million investment through 2012 to add capacity and reduce emissions at our Sherco coal-fired plant;

· a planned investment by the CapX 2020 coalition of utilities of $1.3 billion between 2008 and 2012 to expand the transmission system in the upper Midwest, of which our share of the investment would be approximately $700 million, representing the first phase of CapX 2020; and

· the potential of building an IGCC plant in Colorado and owning wind generation.

As a result of these investments, as well as continued investments in our transmission and distribution system, we expect that our rate base, or the amount on which we earn a return, will grow annually by more than 5 percent on average.

The third phase is earning a fair return on utility system investments. To this end, our regulatory strategy is to receive regulatory approval for rate riders as well as general rate cases. A rate rider is a mechanism that allows recovery of certain costs and returns on investments without the costs and delays of filing a rate case. These riders allow for timely revenue recovery and are good mechanisms to recover the costs of large projects or other costs that vary over time. As an example, a rider for MERP went into effect in January 2006, allowing us to earn a return on the project while the facility is being constructed.

General rate cases have been filed to increase revenue recovery in most of the states in which we operate. In 2006, several rate cases were filed as part of our regulatory strategy. These rate cases, and others planned for 2007, are some of the building blocks of our earnings growth plan. Following is the current status of these initiatives:

· Constructive decisions were received in the Minnesota electric rate case, Colorado natural gas rate case and Wisconsin electric and natural gas cases, which increased revenue in 2006.

· A constructive decision was received in the Colorado electric rate case, which will increase 2007 revenue. (see Factors Affecting Results of Continuing Operations for the further discussion)

· An electric rate case was filed in Texas and gas rate cases in Minnesota, Colorado and North Dakota were filed. We expect decisions in these cases later this year, which should increase revenue in 2007 and 2008.

· Later this year, we plan to file electric and gas cases in Wisconsin and will consider filing cases in other states. If successful, these cases should increase revenue and earnings in 2008.

Our regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility investments. We believe that our commissions will provide reasonable recovery, and it’s important to note that our financial plans include this assumption. Recent constructive results, along with past rulings, are evidence of reasonable regulatory treatment and give us confidence that we are pursuing the right strategy.

With any strategic plan, there are goals and objectives. We feel the following financial objectives are both realistic and achievable:

· Annual earnings-per-share growth rate target of 5 percent to 7 percent;

· Annual dividend increases of 2 percent to 4 percent; and

· Senior unsecured debt credit ratings in the BBB+ to A range.

Successful execution of our Building the Core strategic plan should allow us to achieve our financial objectives, which in turn should provide investors with an attractive total return on a low-risk investment.

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying Consolidated Financial Statements and the related Notes to Consolidated Financial Statements. All note references refer to the Notes to Consolidated Financial Statements.

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of GAAP. Continuing operations consist of the following:

· Regulated utility subsidiaries, operating in the electric and natural gas segments; and

· Several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:

· Quixx Corp., a major portion of which was sold in October 2006;

· Utility Engineering Corp., which was sold in April 2005;

· Seren, a portion of which was sold in November 2005 with the remainder sold in January 2006;

· Cheyenne, which was sold in January 2005;

· NRG, which emerged from bankruptcy and was divested in late 2003; and

· Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

See Note 2 to the Consolidated Financial Statements for a further discussion of discontinued operations.

	Contribution to earnings
	2006				2005				2004
	(Millions of Dollars)
GAAP income by segment
Regulated electric utility segment income — continuing operations		$	503.1			$	440.6			$	466.3
Regulated natural gas utility segment income — continuing operations		70.6				71.2				86.1
Other utility results(a)		32.3				27.6				6.1
Total utility segment income — continuing operations		606.0				539.4				558.5
Holding company costs and other results(a)		(37.3		)		(40.3		)		(36.2		)
Total income — continuing operations		568.7				499.1				522.3
Regulated utility income (loss) — discontinued operations		3.0				0.2				(9.0		)
Other nonregulated income (loss) — discontinued operations		0.1				13.7				(157.3		)
Total income (loss) — discontinued operations		3.1				13.9				(166.3		)
Total GAAP net income		$	571.8			$	513.0			$	356.0

	Contribution to earnings per share
	2006				2005				2004
GAAP earnings per share contribution by segment
Regulated electric utility segment — continuing operations		$	1.17			$	1.04			$	1.10
Regulated natural gas utility segment — continuing operations		0.16				0.17				0.20
Other utility results(a)		0.08				0.06				0.02
Total utility segment earnings per share — continuing operations		1.41				1.27				1.32
Holding company costs and other results(a)		(0.06		)		(0.07		)		(0.06		)
Total earnings per share — continuing operations		1.35				1.20				1.26
Regulated utility earnings (loss) — discontinued operations		0.01				—				(0.02		)
Other nonregulated earnings (loss) — discontinued operations		—				0.03				(0.37		)
Total earnings (loss) per share — discontinued operations		0.01				0.03				(0.39		)
Total GAAP earnings per share — diluted		$	1.36			$	1.23			$	0.87

(a) Not a reportable segment. Included in All Other segment results in Note 17 to the Consolidated Financial Statements.

Earnings from continuing operations for 2006 were higher than in 2005. The increase in 2006 earnings was primarily due to stronger base electric utility margin. The higher margin reflects electric rate increases in various jurisdictions, weather-adjusted retail electric sales growth and revenue associated with investments in MERP. In addition, earnings increased due to the recognition of income tax benefits. Partially offsetting these positive factors were expected increases in expenses for operations, maintenance and depreciation and lower short-term wholesale margins.

Earnings from continuing operations for 2005 were lower than in 2004. The 2005 results had higher operating margins, which were offset by higher operating and maintenance expenses, including scheduled nuclear plant outages in 2005, higher employee benefit costs, higher uncollectible receivable expense and higher depreciation expense. In addition, tax expense recorded in 2005 was higher than 2004, primarily attributable to tax benefits recorded in 2004 related to the successful resolution of various income tax audit issues.

Income from discontinued operations in 2005 includes the positive impact of a $17 million tax benefit recorded to reflect the final resolution of Xcel Energy’s divested interest in NRG. This was partially offset by Seren’s operating losses during 2005.

The loss from discontinued operations in 2004 is largely due to an after-tax impairment charge of $143 million, or 34 cents per share, related to Seren. In addition, the loss from discontinued operations in 2004 is attributable in part to an after-tax loss of $13 million, or 3 cents per share, associated with the disposition of Cheyenne.

	Contribution to earnings
	2006			2005			2004
Earnings Contribution by Company
NSP-Minnesota		47.4	%		46.6	%		43.0	%
PSCo		41.5			41.7			41.3
SPS		8.1			12.5			10.3
NSP-Wisconsin		7.4			5.0			10.3
Total regulated utility contribution		104.4			105.8			104.9
Holding company and other subsidiaries		(4.4	)		(5.8	)		(4.9	)
Total earnings contributions		100.0	%		100.0	%		100.0	%

Weather — Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature.

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

· Weather in 2006 increased earnings by an estimated 2 cents per share;

· Weather in 2005 increased earnings by an estimated 3 cents per share; and

· Weather in 2004 decreased earnings by an estimated 8 cents per share.

Statement of Operations Analysis — Continuing Operations

The following discussion summarizes the items that affected the individual revenue and expense items reported in the Consolidated Statements of Income.

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 in most states, the fluctuations in these costs do not materially affect electric utility margin.

Xcel Energy 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 financial instruments associated with the fuel required for, and energy produced from, Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with Xcel Energy’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.

Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable. Commodity trading revenues 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.

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

	Base Electric Utility				Short-Term Wholesale				Commodity Trading				Consolidated Totals
	(Millions of Dollars)
2006
Electric utility revenue (excluding commodity trading)		$	7,387			$	201			$	—			$	7,588
Fuel and purchased power		(3,925		)		(178		)		—				(4,103		)
Commodity trading revenue		—				—				610				610
Commodity trading costs		—				—				(590		)		(590		)
Gross margin before operating expenses		$	3,462			$	23			$	20			$	3,505
Margin as a percentage of revenue		46.9		%		11.4		%		3.3		%		42.8		%
2005
Electric utility revenue (excluding commodity trading)		$	7,038			$	196			$	—			$	7,234
Fuel and purchased power		(3,802		)		(120		)		—				(3,922		)
Commodity trading revenue		—				—				730				730
Commodity trading costs		—				—				(720		)		(720		)
Gross margin before operating expenses		$	3,236			$	76			$	10			$	3,322
Margin as a percentage of revenue		46.0		%		38.8		%		1.4		%		41.7		%
2004
Electric utility revenue (excluding commodity trading)		$	5,989			$	220			$	—			$	6,209
Fuel and purchased power		(2,916		)		(125		)		—				(3,041		)
Commodity trading revenue		—				—				610				610
Commodity trading costs		—				—				(594		)		(594		)
Gross margin before operating expenses		$	3,073			$	95			$	16			$	3,184
Margin as a percentage of revenue		51.3		%		43.2		%		2.6		%		46.7		%

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

Base Electric Utility Revenue

	2006 vs. 2005
	(Millions of Dollars)
NSP-Minnesota electric rate changes		$	129
Fuel and purchased power cost recovery		61
Sales growth (excluding weather impact)		45
NSP-Wisconsin rate case		41
MERP rider		38
Conservation and non-fuel riders		24
Quality of service obligations		12
SPS Texas surcharge decision		(8		)
SPS FERC 206 rate refund accrual		(8		)
Other		15
Total base electric utility revenue increase		$	349

2006 Comparison with 2005 — Base electric utility revenues increased due to rate increases in Minnesota and Wisconsin, higher fuel and purchased power costs, largely recoverable from customers, weather-normalized retail sales growth of approximately 1.8 percent, and the implementation of the MERP rider to recover financing and other costs related the MERP construction projects.

	2005 vs. 2004
	(Millions of Dollars)
Fuel and purchased power cost recovery		$	706
Estimated impact of weather		91
Firm wholesale		67
Sales growth (excluding weather impact)		57
Texas fuel reconciliation settlement		21
Conservation and non-fuel riders		16
Capacity sales		15
Quality of service obligations		7
Other		69
Total base electric utility revenue increase		$	1,049

2005 Comparison with 2004 — Base electric utility revenues increased due to higher fuel and purchased power costs, which are largely recovered from customers; weather-normalized retail sales growth of approximately 1.4 percent; higher sales attributable to warmer than normal summer temperatures in 2005; higher revenues from firm wholesale customers and lower regulatory accruals related to the Texas fuel reconciliation settlement.

Base Electric Utility Margin

	2006 vs. 2005
	(Millions of Dollars)
NSP-Minnesota electric rate changes		$	129
NSP-Wisconsin rate changes, including fuel and purchased power cost recovery		41
Sales growth (excluding weather impact)		39
MERP rider		38
Conservation and non-fuel rider revenue		24
Firm wholesale		12
Quality-of-service obligations		12
Transmission fee classification change		(26		)
PSCo ECA incentive		(20		)
SPS Texas surcharge decision		(8		)
SPS FERC 206 rate refund accrual		(8		)
Estimated impact of weather		(3		)
Other, including certain regulatory reserves		(4		)
Total base electric utility margin increase		$	226

2006 Comparison to 2005 — Base electric utility margins, which are primarily derived from retail customer sales, increased due to rate increases in Minnesota and Wisconsin, weather-normalized retail sales growth, the implementation of the MERP rider, and higher firm wholesale margins. Partially offsetting the increase, is a transmission fee classification change from other operating and maintenance expenses-utility in 2005 to electric utility margin in 2006, which did not impact operating income or net income. The change resulted from an analysis conducted in conjunction with the expiration and renegotiation of certain transmission agreements, resulting in better alignment of reporting such costs consistent with MISO classification. In addition, the ECA incentive earned in Colorado in 2006 resulted in a loss, as compared to a gain in 2005.

Base Electric Utility Margin

	2005 vs. 2004
	(Millions of Dollars)
Estimated impact of weather		$	75
Sales growth (excluding weather impact)		42
Firm wholesale		23
Texas fuel reconciliation settlement		21
Conservation and non-fuel revenue		16
Quality-of-service obligations		7
Under-recovery of fuel costs (NSP-Wisconsin)		(15		)
Under-recovery and timing of recovery of fuel costs (other jurisdictions)		(14		)
Pricing and other		8
Total base electric utility margin increase		$	163

2005 Comparison to 2004 — Base electric utility margin increased due to the impact of weather, weather-normalized sales growth, higher firm wholesale margins, higher conservation and non-fuel rider revenues and lower accruals related to the fuel reconciliation proceedings in Texas, partially offset by higher amortization expense and lower regulatory accruals associated with potential customer refunds related to service-quality obligations in Colorado. These increases were partially offset by higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms.

Short-Term Wholesale and Commodity Trading Margin

2006 Comparison to 2005 — As expected, short-term wholesale and commodity trading margins declined by $43 million for 2006 compared with 2005, due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, reductions in the availability of the coal-fired King plant due to the MERP project, decreased opportunities to sell due to the MISO centralized dispatch market, and the Minnesota rate case settlement agreement to refund to customers the majority of short-term wholesale margins attributable to Minnesota jurisdiction customers starting in 2006.

2005 Comparison to 2004 — Short-term wholesale and commodity trading margins decreased $25 million for 2005 compared with 2004. The higher 2004 results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell. In addition, a preexisting contract contributed $17 million of margin in the first quarter of 2004 and expired at that time.

Natural Gas Utility Revenue and Margins

The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin. See further discussion under Factors Affecting Results of Continuing Operations.

	2006				2005				2004
	(Millions of Dollars)
Natural gas utility revenue		$	2,156			$	2,307			$	1,916
Cost of natural gas purchased and transported		(1,645		)		(1,823		)		(1,446		)
Natural gas utility margin		$	511			$	484			$	470

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

Natural Gas Revenue

	2006 vs. 2005				2005 vs. 2004
	(Millions of Dollars)
Base rate changes		$	32			$	6
Purchased natural gas cost recovery		(147		)		397
Estimated impact of weather		(33		)		(5		)
Sales decline (excluding weather impact)		(8		)		—
Transportation and other		5				(7		)
Total natural gas revenue (decrease) increase		$	(151	)		$	391

2006 Comparison to 2005 — Natural gas revenue decreased primarily due to lower natural gas costs in 2006, which are recovered from customers. Retail natural gas weather-normalized sales declined when compared to 2005, largely due to declining use per customer.

2005 Comparison to 2004 — Natural gas revenue increased primarily due to higher natural gas costs in 2005, which are recovered from customers. Retail natural gas weather-normalized sales were flat when compared to 2004, largely due to the rising cost of natural gas and its impact on customer usage.

Natural Gas Margin

	2006 vs. 2005				2005 vs. 2004
	(Millions of Dollars)
Base rate changes — all jurisdictions		$	32			$	6
Transportation		8				6
Sales (decline) growth, excluding weather impact		(7		)		1
Estimated impact of weather		(4		)		(2		)
Other		(2		)		3
Total natural gas margin increase		$	27			$	14

2006 Comparison to 2005 — Natural gas margins increased in 2006 due to rate increases in Colorado, Wisconsin and Minnesota. Base rate changes include a full year of new rates for Minnesota in 2006 as compared to two months of increase in 2005.

2005 Comparison to 2004 — Natural gas margin increased in 2005 due to rate changes in Minnesota and North Dakota, and higher transportation margins, partially offset by the impact of warmer winter temperatures in 2005 compared with 2004.

Non-Fuel Operating Expenses and Other Items

Other Utility Operating and Maintenance Expenses

	2006 vs. 2005
	(Millions of Dollars)
Transmission fees classification change		$	(26	)
Private Fuel Storage regulatory asset		(17		)
Gains on sale or disposal of assets, net		(9		)
Lower nuclear plant outage costs		(4		)
Higher employee benefit costs, primarily performance-based		38
Higher combustion/hydro plant costs		24
Higher nuclear plant operating costs		22
Higher uncollectible receivable costs		15
Higher consulting costs		8
Higher conservation incentive program costs		4
Other, including fleet transportation and facilities costs		9
Total utility operating and maintenance expense increase		$	64

2006 Comparison to 2005 — Other utility operating and maintenance expenses for 2006 increased $64 million, or 3.8 percent, compared with 2005. Higher employee benefit costs, which are primarily performance-based, higher nuclear and combustion/hydro plant costs were offset by lower nuclear plant outage costs, the transmission reclassification, gains on sale of assets, and the establishment of the Private Fuel Storage regulatory asset, based on a regulatory decision.

	2005 vs. 2004
	(Millions of Dollars)
Lower plant-related costs		$	(7	)
Lower information technology costs		(6		)
Higher employee benefit costs		31
Higher nuclear plant outage costs		26
Higher uncollectible receivable costs		19
Higher electric service reliability costs		9
Higher donations to energy assistant programs		4
Higher costs related to customer billing system conversion		4
Higher mutual aid assistance costs		1
Other		6
Total utility operating and maintenance expense increase		$	87

2005 Comparison to 2004 — Other utility operating and maintenance expenses for 2005 increased by approximately $87 million, or 5.5 percent, compared with 2004. An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005 increased costs by approximately $26 million. Employee benefit costs were higher in 2005, primarily due to increased pension benefits and long-term disability costs. Also contributing to the increase was higher uncollectible receivable costs, attributable in part, to modifications to the bankruptcy laws, higher fuel prices and certain changes in the credit and collection process.

Other Nonregulated Operating and Maintenance Expenses — Other nonregulated operating and maintenance expenses decreased $16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement related to shareholder lawsuits.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $55 million, or 7.1 percent, for 2006 compared with 2005. Decommissioning accruals increased $20 million in 2006. Normal plant additions accounted for the remaining increase in depreciation expense for 2006 over 2005.

Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent, compared with 2004. The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions, both of which have relatively short depreciable lives compared with other capital additions. The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013. In addition, the Minnesota Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not have an impact on net income, increased over 2004. The increase was partially offset by the changes in useful lives and net salvage rates approved by the MPUC in August 2005.

AFDC — AFDC increased in total by approximately $14 million for 2006 when compared to 2005. The increase was due primarily to large capital projects beginning in 2005 and 2006, including MERP and Comanche 3, with long construction periods. The increase was partially offset by the current recovery from customers of the financing costs related to MERP through a MERP rider resulting in a lower recognition of AFDC.

AFDC decreased by approximately $15 million in 2005, compared with 2004, due to generally lower AFDC rates and construction work in progress balances.

Interest and Other Income (Expense) Net — Interest and other income (expense) net increased $3 million in 2006 compared to 2005. The increase is due primarily to higher interest income on temporary cash investments, and the deferred fuel assets in Texas.

Interest and other income (expense) net decreased $8 million in 2005 compared with 2004. The decrease is due to interest income related to the finalization of prior-period IRS audits of $11 million in 2004, partially offset by a $2 million gain on the sale of water rights in 2005.

Interest and Financing Costs — Interest charges increased by approximately $24 million, or 5.1 percent, for 2006 compared with 2005. The increase is due to higher levels of both short-term and long-term debt and higher short-term interest rates.

The 2005 interest charges and financing costs increased approximately $8 million, or 1.9 percent, when compared with 2004, primarily due to increased short term borrowing levels.

Income Tax Expense — Income taxes for continuing operations increased by $8 million for 2006, compared with 2005. The effective tax rate for continuing operations was 24.2 percent for 2006, compared with 25.8 percent for 2005. The increase in income tax expense was primarily due to an increase in pretax income, partially offset by $30 million of tax benefits from the reversal of a regulatory reserve and realized capital loss carryforwards. Without these tax benefits the effective tax rate for 2006 would have been 28.2 percent.

The effective income tax rate for continuing operations was 25.8 percent for 2005, compared with 23.7 percent in 2004. Income taxes recorded in 2005 reflect tax benefits of $10 million, primarily from increased research credits and a net operating loss carry back. Excluding the tax benefits, the effective rate for 2005 would have been 27.3 percent.

See Note 7 to the Consolidated Financial Statements.

Holding Company and Other Results

The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results:

	Contribution to Xcel Energy’s earnings
	2006				2005				2004
	(Millions of Dollars)
Eloigne		$	4.6			$	6.2			$	8.5
Financing costs — holding company		(66.1		)		(52.7		)		(44.7		)
Holding company, taxes and other results		24.2				6.2				—
Total holding company and other loss — continuing operations		$	(37.3	)		$	(40.3	)		$	(36.2	)

	Contribution to Xcel Energy’s earnings per share
	2006				2005				2004
Eloigne		$	0.01			$	0.01			$	0.02
Financing costs and preferred dividends — holding company		(0.12		)		(0.09		)		(0.08		)
Holding company, taxes and other results		0.05				0.01				—
Total holding company and other loss per share — continuing operations		$	(0.06	)		$	(0.07	)		$	(0.06	)

Financing Costs and Preferred Dividends — Holding company and other results include interest expense and the earnings-per-share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.

The earnings-per-share impact of financing costs and preferred dividends for 2006, 2005 and 2004 included above reflects dilutive securities, as discussed further in Note 8 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of interest expense resulting in an increase in net income of approximately $15 million in 2006; $14 million in 2005; and $15 million in 2004.

Statement of Operations Analysis — Discontinued Operations (Net of Tax)

A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:

	2006				2005				2004
Income (loss) in millions
Viking Gas Transmission Co.		$	—			$	—			$	1.3
Cheyenne		3.0				0.2				(10.3		)
Regulated utility segments — income (loss)		3.0				0.2				(9.0		)
NRG		(0.5		)		16.1				(12.8		)
Xcel Energy International		(0.5		)		0.1				7.3
e prime		0.1				(0.1		)		(1.8		)
Seren		2.1				1.8				(156.6		)
Utility Engineering Corp. / Quixx Corp.		(0.7		)		(4.4		)		4.7
Other		(0.4		)		0.2				1.9
Nonregulated/other — income (loss)		0.1				13.7				(157.3		)
Total income (loss) from discontinued operations		$	3.1			$	13.9			$	(166.3	)
Income (loss) per share
Viking Gas Transmission Co.		$	—			$	—			$	—
Cheyenne		0.01				—				(0.02		)
Regulated utility segments — income (loss) per share		0.01				—				(0.02		)
NRG		—				0.04				(0.03		)
Xcel Energy International		—				—				0.02
e prime		—				—				—
Seren		—				—				(0.37		)
Utility Engineering, Corp. / Quixx Corp.		—				(0.01		)		0.01
Other		—				—				—
Nonregulated/other — income (loss) per share		—				0.03				(0.37		)
Total income (loss) per share from discontinued operations		$	0.01			$	0.03			$	(0.39	)

Regulated Utility Results — Discontinued Operations

In January 2004, Xcel Energy agreed to sell Cheyenne. Consequently, Xcel Energy reported Cheyenne results as a component of discontinued operations for all periods presented. The sale was completed in January 2005 and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued in December 2004. In 2006, the Cheyenne basis study was updated resulting in the recognition of $2.3 million in tax benefits. This plus other Cheyenne related tax benefits totaled $3.3 million or 1 cent per share.

Other and Nonregulated Results — Discontinued Operations

In April 2005, Zachry Group, Inc. (Zachry) acquired all of the outstanding shares of UE, a nonregulated subsidiary. The majority of Quixx Corp., including Borger Energy Associates and Quixx Power Services, Inc., was sold in October 2006 to affiliates of Energy Investors Funds.

In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings, LLC. In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communications.

During 2004, Xcel Energy completed the sales of the Argentina subsidiaries of Xcel Energy International and e prime ceased conducting business.

2005 Nonregulated Results Compared with 2004 — Results of discontinued nonregulated operations in 2005 include the impact of a $5 million reduction to the original asset impairment for Seren and the positive impact of a $17 million tax benefit recorded to reflect the final resolution of Xcel Energy’s divested interest in NRG. In 2004, the NRG tax basis study was updated and previously recognized tax benefits were reduced by $13 million.

Tax Benefits Related to Investment in NRG — Xcel Energy has recognized tax benefits related to the divestiture of NRG of approximately $1.1 billion. Since these tax benefits are related to Xcel Energy’s investment in discontinued NRG operations, they are reported as discontinued operations.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $404 million of these tax benefits through 2005, an additional $223 million in 2006, and expects to use approximately $123 million in 2007. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

Factors Affecting Results of Continuing Operations

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and affect Xcel Energy’s ability to recover its costs from customers. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by a number of factors, including the following:

General Economic Conditions

Economic conditions may have a material impact on Xcel Energy’s operating results. Management cannot predict the impact of a future economic slowdown, fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital resulting from a general slowdown in future economic growth or a significant increase in interest rates.

Sales Growth

In addition to the impact of weather, customer sales levels in Xcel Energy’s utility businesses can vary with economic conditions, energy prices, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was 1.8 percent in 2006, and 1.4 percent in 2005. Weather-normalized sales growth for firm natural gas utility customers was approximately (2.8) percent in 2006, and 0.2 percent in 2005. Weather-normalized sales for 2007 are projected to grow between 1.7 percent and 2.2 percent for retail electric utility customers and a sales decline of 1.0 percent to 2.0 percent for retail natural gas utility customers.

Fuel Supply and Costs

Coal Deliverability — Xcel Energy’s operating utilities have varying dependence on coal-fired generation. Coal-fired generation comprises between 60 percent and 85 percent of the total annual generation. Approximately 85 percent of the annual coal requirements are supplied from the Powder River Basin in Wyoming.

Delivery of coal was hampered during early 2006 due to disruptions caused by train derailments and continuing operational problems that started during the summer of 2005 along a key rail line in Wyoming. Coal conservation was necessary at several plants during this time that included increased purchased power and increasing the use of natural gas for electric generation.

However, coal inventory improved significantly during the latter part of 2006, due in large part to rail transportation improvements. In addition, Xcel Energy acquired higher capacity railcars that facilitated inventory rebuilding. For 2007, inventory sustainability will be a critical goal, however, no mitigation efforts are expected.

Pension Plan Costs and Assumptions

Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 9 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs have been increasing in recent years, but are expected to decrease over the next several years, due to higher-than-expected investment returns experienced in recent years, as well as, voluntary company contributions. While investment returns exceeded the assumed level of 8.75 percent in 2006 and 2005 and 9.0 percent in 2004, investment returns in 2003 and 2002 were below the assumed level of 9.25 and 9.5 percent respectively, and discount rates have declined to 5.75 percent used in 2006. Xcel Energy continually reviews its pension assumptions and, in 2007, expects to maintain the investment return assumption at 8.75 percent and to increase the discount rate assumption to 6.00 percent.

The investment gains or losses resulting from the difference between the expected pension returns assumed on asset levels and actual returns earned are deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost-determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on current assumptions and the recognition of past investment gains and losses over the next five years, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes in continuing operations will decrease from an expense, of $15.3 million in 2006 to an expense of $11.8 million in 2007 and $6.3 million in 2008.

Xcel Energy bases its discount rate assumption on benchmark interest rates from Moody’s. At Dec. 31, 2006, the annualized Moody’s Baa index rate was 6.35 percent, and the Aaa index rate was 5.46 percent. Accordingly, Xcel Energy increased the discount rate to 6.00 percent as of Dec. 31, 2006. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2007 pension cost determinations. At Dec. 31, 2005, the annualized Moody’s Baa index rate was 6.21 percent and the Aaa index rate was 5.26 percent. The corresponding pension discount rate was 5.75 percent.

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impact on the estimated pension costs recognized by Xcel Energy:

· A 100 basis point higher rate of return, 9.75 percent, would decrease 2007 recognized pension costs by $20.2 million;

· A 100 basis point lower rate of return, 7.75 percent, would increase 2007 recognized pension costs by $20.2 million;

· A 100 basis point higher discount rate, 7.00 percent, would decrease 2007 recognized pension costs by $4.6 million; and

· A 100 basis point lower discount rate, 5.00 percent, would increase 2007 recognized pension costs by $5.5 million.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Xcel Energy projects that no cash funding would be required for 2007 or 2008. However, the Company expects to make voluntary contributions in 2007 to maintain a level of funded status that allows for future funding flexibility and reduces cash flow volatility under the Pension Protection Act. These expected contributions are summarized in Note 9 to

the Consolidated Financial Statements. These amounts are estimates and may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future.

Regulation

PUHCA 2005 — The Energy Act significantly changed many federal statutes and repealed the PUHCA as of Feb. 8, 2006. However, the FERC was given authority to review the books and records of holding companies and their nonutility subsidiaries, authority to review service company accounting and cost allocations, and more authority over the merger and acquisition of public utilities. State commissions have similar authority to review the books and records of holding companies and their nonutility subsidiaries.

The Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and the DOE. The FERC and the DOE are in various stages of rulemaking in implementing the Energy Act.

Customer Rate Regulation — The FERC and various state regulatory commissions regulate Xcel Energy’s utility subsidiaries. Decisions by these regulators can significantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions.

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s financial results. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales growth, conservation and demand-side management efforts, and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in rate proceedings. The most recently authorized electric utility returns are 10.54 percent for NSP-Minnesota; 11.0 percent for NSP-Wisconsin; 10.5 percent for PSCo; and 11.5 percent for SPS. The most recently authorized natural gas utility returns are 10.4 percent for NSP-Minnesota, 11.0 percent for NSP-Wisconsin and 10.5 percent for PSCo.

Wholesale Energy Market Regulation — In April 2005, a Day 2 wholesale energy market operated by MISO was implemented to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. MISO now centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin. NSP-Minnesota and NSP-Wisconsin expect to recover MISO charges through either base rates or various recovery mechanisms. See Note 13 to the Consolidated Financial Statements for further discussion.

Capital Expenditure Regulation — Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy transmission and distribution systems. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, the CPUC and MPUC approved proposals to recover, through a rate rider, costs to upgrade generation plants, lower emissions and increased transmission. These rate riders are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.

Future Cost Recovery — Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods, and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, other companies would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, Xcel Energy 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. This could have a material effect on Xcel Energy’s results of operations in the period the write-off is recorded.

At Dec. 31, 2006, Xcel Energy reported on its balance sheet regulatory assets of approximately $1.2 billion and regulatory liabilities of approximately $1.4 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. See Notes 1 and 16 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

Tax Matters

Interest Expense Deductibility — 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.

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.

Environmental Matters

Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital expenditures for environmental compliance.

In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and waste were approximately:

· $152 million in 2006;

· $147 million in 2005; and

· $133 million in 2004.

Xcel Energy expects to expense an average of approximately $176 million per year from 2007 through 2011 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

Capital expenditures for environmental improvements at regulated facilities were approximately:

· $571.2 million in 2006;

· $327.7 million in 2005; and

· $57.6 million in 2004.

Xcel Energy expects to incur approximately $323 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2007, and approximately $575 million of related expenditures from 2008 through 2011. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado. Approximately $213 million and $232 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants pursuant to the MERP. Expected expenditures related to environmental modifications on Comanche Units 1 and 2 are approximately $41 million in 2007 and $26 million from 2008 through 2011. The remaining expected capital expenditures relate to various other environmental projects. In addition, NSP-Minnesota has proposed a $905 million upgrade at the Sherburne County (Sherco) coal-fired power plant. The project will increase capacity and reduce emissions. The MPUC is expected to rule on the project in 2008. If approved, construction would start in late 2008 and be completed in 2012. See Note 14 to the Consolidated Financial Statements for further discussion of Xcel Energy’s environmental contingencies.

The EPA’s CAIR impacts Xcel Energy generating facilities in Minnesota, Wisconsin, and Texas. The MPCA and WDNR are working on drafting rules that will require more stringent emission reductions than required by the federal program in Minnesota and Wisconsin. Currently, there is litigation concerning whether the EPA should reconsider the inclusion of West Texas in CAIR. The outcome of this litigation will impact compliance options for the Texas generating facilities.

States throughout the Xcel Energy territory are implementing the federal mercury rule in various ways. In Minnesota mercury emissions from A.S. King and Sherburne County generating facilities will be regulated by the Minnesota Mercury Legislation, while the remaining Minnesota generating facilities will be regulated by the CAMR. In Colorado the Air Pollution Control Commission recently passed a mercury emissions rule. Texas implemented the EPA’s CAMR.

The EPA requires states to develop implementation plans to comply with the BART/Regional amendments by December 2007. The MPCA has not responded to NSP-Minnesota’s BART alternatives analysis submittal. In response to the BART regulations promulgated by the Colorado Air Quality Control Commission, PSCo submitted its BART alternatives analysis. PSCo is discussing its BART alternatives analysis with the CAPCD. The TCEQ has determined that compliance with CAIR is a substitute for BART for NOx and SO2.

In January NSP-Minnesota made a filing to the MPUC concerning an emissions reduction project at the Sherco generating facility. The improvement project would include generating capacity upgrades for all three units; additional SO2 emission reductions on Units 1 and 2 to improve mercury emission controls; and the installation of additional NOx controls.

The issue of global climate change is receiving increased attention. There is considerable debate regarding the public policy approach that the United States should follow to address the issue. Several members of Congress have also proposed legislation to regulate carbon dioxide, and several states are developing their own programs to address climate change.

While it is not possible to know the eventual outcome, Xcel Energy is taking prudent steps to address the risk of potential climate regulation. Xcel Energy’s initiatives to prepare for potential carbon dioxide regulation include the following:

· Xcel Energy is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009, and to reduce carbon intensity by 7 percent by 2012.

· In certain regulatory jurisdictions, Xcel Energy uses an evaluation process for future generating resources that incorporates the risk of future carbon limits through the use of a carbon cost adder or externality costs.

· PSCo is in the process of developing an IGCC plant that generates electricity using gasified coal and will be the first plant of its kind to capture and sequester a portion of the carbon dioxide generated by the plant.

· Xcel Energy is the largest retail provider of wind generated energy in the nation and continues to grow its wind portfolio.

· Xcel Energy is involved in initiatives to manage carbon dioxide, including the use of biosequestration and the study of geological sequestration.

· Xcel Energy continues to develop and expand its customer conservation and demand side management programs.

· Xcel Energy is working with public policy makers to support the development of a national climate policy to require the deployment of electric generation technology that emits little or no carbon dioxide.

Xcel Energy believes that it is well positioned for a variety of possible outcomes.

Impact of Nonregulated Investments

In the past, Xcel Energy’s investments in nonregulated operations had a significant impact on its results of operations. As a result of the divestiture of NRG and other nonregulated operations, Xcel Energy does not expect that its investments in nonregulated operations will continue to have a significant impact on its results.

Inflation

Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders.

Critical Accounting Policies and Estimates

Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the Consolidated Financial Statements and disclosures, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results reported even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the audit committee of the Xcel Energy board of directors.

Accounting Policy	Judgments/Uncertainties Affecting Application	See Additional Discussion At
Regulatory Mechanisms and Cost Recovery	· Anticipated future regulatory decisions and their impact · External regulatory decisions, requirements and regulatory environment · Impact of deregulation and competition on ratemaking process and ability to recover costs	Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations · Regulation Notes to Consolidated Financial Statements · Notes 1, 12, 13, 14 and 16
Nuclear Plant Decommissioning and Cost Recovery	· Costs of future decommissioning · Availability of facilities for waste disposal · Approved methods for waste disposal · Useful lives of nuclear power plants · Future recovery of plant investment and decommissioning costs · Re-licensing of nuclear plants impact on decommissioning costs	Notes to Consolidated Financial Statements · Notes 1, 14 and 15
Income Tax Accruals	· Application of tax statutes and regulations to transactions · Anticipated future decisions of tax authorities · Ability of tax authority decisions/positions to withstand legal challenges and appeals · Ability to realize tax benefits through carry backs to prior periods or carry overs to future periods	Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations · Tax Matters Notes to Consolidated Financial Statements · Notes 1, 7 and 14
Benefit Plan Accounting	· Future rate of return on pension and other plan assets, including impact of any changes to investment portfolio composition · Discount rates used in valuing benefit obligation · Actuarial period selected to recognize deferred investment gains and losses	Management’s Discussion and Analysis: Factors Affecting Results of Continuing Operations · Pension Plan Costs and Assumptions Notes to Consolidated Financial Statements · Notes 1 and 9

Xcel Energy continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. For example:

· Probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators.

· The ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by Xcel Energy’s regulators, is assumed.

· Probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed.

· Projections are made regarding earnings on pension investments, and the salary increases provided to employees over their periods of service.

The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2006.

For a discussion of significant accounting policies, see Note 1 to the Consolidated Financial Statements.

Pending Accounting Changes

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 measurement of uncertain tax positions would be reflected as a component of income tax expense.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. Xcel Energy 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. Xcel Energy 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.

Derivatives, Risk Management and Market Risk

In the normal course of business, Xcel Energy and its subsidiaries are 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 Xcel Energy and its subsidiaries, are discussed in further detail later.

Commodity Price Risk — Xcel Energy and its subsidiaries are exposed to commodity price risk in their 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. Xcel Energy’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 — Xcel Energy’s subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of capacity, energy and energy-related instruments. These marketing activities have terms of generally less than one year in length. Xcel Energy’s risk-management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

The fair value of the commodity trading contracts as of Dec. 31, 2006, was as follows:

	(Millions of Dollars)
Fair value of trading contracts outstanding at Jan. 1, 2006		$	3.9
Contracts realized or settled during the year		(18.4		)
Fair value of trading contract additions and changes during the year		13.3
Fair value of trading contracts outstanding at Dec. 31, 2006		$	(1.2	)

As of Dec. 31, 2006, the fair values by source for the commodity trading and hedging net asset or liability balances were as follows:

Commodity Trading Contracts

	Futures/Forwards
	Source of Fair Value		Maturity Less Than 1 Year				Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Futures/ Forwards Fair Value
	(Thousands of Dollars)
NSP-Minnesota		1		$	(1,284	)		$	—		$	—		$	—		$	(1,284	)
		2		226				100			44			—			370
PSCo		1		(2,642		)		—			—			—			(2,642		)
		2		4,029				2,405			—			—			6,434
SPS*		1		130				—			—			—			130
		2		350				160			61			—			571
Total Futures/Forwards Fair Value				$	809			$	2,665		$	105		$	—		$	3,579

	Options
	Source of Fair Value		Maturity Less Than 1 Year				Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Options Fair Value
	(Thousands of Dollars)
NSP-Minnesota		2		$	(435	)		$	—		$	—		$	—		$	(435	)
PSCo		2		(4,412		)		—			—			—			(4,412		)
SPS*		2		93				—			—			—			93
Total Options Fair Value				$	(4,754	)		$ —			$ —			$	—		$	(4,754	)

Commodity Hedge Contracts

	Futures/Forwards
	Source of Fair Value		Maturity Less Than 1 Year				Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Futures/ Forwards Fair Value
	(Thousands of Dollars)
NSP-Minnesota		1		$	(2,229	)		$	—		$	—		$	—		$	(2,229	)
		2		16,420				—			—			—			16,420
PSCo		1		(166		)		—			—			—			(166		)
NSP-Wisconsin		1		(250		)		—			—			—			(250		)
Total Futures/Forwards Fair Value				$	13,775			$	—		$	—		$	—		$	13,775

	Options
	Source of Fair Value		Maturity Less Than 1 Year			Maturity 1 to 3 Years			Maturity 4 to 5 Years			Maturity Greater Than 5 Years			Total Options Fair Value
	(Thousands of Dollars)
NSP-Minnesota		2		$	514		$	—		$	—		$	—		$	514
PSCo		2		3,241			—			—			—			3,241
NSP-Wisconsin		2		20			—			—			—			20
Total Options Fair Value				$	3,775		$	—		$	—		$	—		$	3,775

1	—	Prices actively quoted or based on actively quoted prices.
2	—	Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.
*	—	SPS conducts an inconsequential amount of commodity trading. Margins from commodity trading activity are partially redistributed to SPS, NSP-Minnesota, and PSCo, pursuant to the JOA approved by the FERC. As a result of the JOA, margins received pursuant to the JOA are reflected as part of the fair values by source for the commodity trading net asset or liability balances.

Normal purchases and sales transactions, as defined by SFAS No. 133 and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations and are not qualifying hedges.

At Dec. 31, 2006, a 10-percent increase in market prices over the next 12 months for commodity trading contracts would increase pretax income from continuing operations by approximately $0.9 million, whereas a 10-percent decrease would decrease pretax income from continuing operations by approximately $1.1 million.

Xcel Energy’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as 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. Xcel Energy 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:

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


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

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

Interest Rate Risk — Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s 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.

Xcel Energy engages in hedges of cash flow and fair value 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 Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $7.0 million and $10.3 million, respectively. See Note 11 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.

Xcel Energy and its subsidiaries also maintain trust funds, as required by the NRC, to fund costs of nuclear decommissioning. These trust funds are subject to interest rate risk and equity price risk. As of Dec. 31, 2006 and 2005, these funds were invested primarily in domestic and international equity securities and fixed-rate fixed-income securities. These funds may be used only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices or interest rates do not have an impact on earnings.

Credit Risk — Xcel Energy and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms, 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.

At Dec. 31, 2006, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $8.1 million, while a decrease of 10 percent would have resulted in a decrease of $7.3 million.

Liquidity and Capital Resources

Cash Flows

	2006			2005			2004
	(Millions of Dollars)
Cash provided by (used in) operating activities
Continuing operations		$	1,729		$	1,131		$	1,128
Discontinued operations		195			53			(315		)
Total		$	1,924		$	1,184		$	813

Cash provided by operating activities for continuing operations increased $598 million during 2006. The increase is primarily due to the timing of working capital activity. Specifically, the collection of receivables and the collection of recoverable purchased natural gas and electric energy costs increased in 2006. The increase in cash provided by operations was partially offset by the timing of cash expenditures for accounts payable. Cash provided by operating activities for discontinued operations increased $150 million during 2006, largely due to the recognition of deferred tax assets related to NRG.

Cash provided by operating activities for continuing operations was basically unchanged for 2005 and 2004. Cash provided by operating activities for discontinued operations increased $368 million during 2005 compared with 2004. During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by tax benefits received.

	2006				2005				2004
	(Millions of Dollars)
Cash provided by (used in) investing activities
Continuing operations		$	(1,601	)		$	(1,362	)		$	(1,268	)
Discontinued operations		51				136				37
Total		$	(1,550	)		$	(1,226	)		$	(1,231	)

Cash used in investing activities for continuing operations increased $239 million during 2006, primarily due to increased utility capital expenditures, partially offset by a decrease in restricted cash and proceeds from the sale of assets. Cash provided by investing activities for discontinued operations decreased $84 million during 2006, primarily due to the receipt of proceeds from the sale of Cheyenne and Seren in 2005.

Cash used in investing activities for continuing operations increased $94 million during 2005, primarily due to increased utility capital expenditures and restricted cash released in 2004. Cash provided by investing activities for discontinued operations increased $99 million during 2005, primarily due to the receipt of proceeds from the sale of Cheyenne and Seren in 2005.

	2006				2005			2004
	(Millions of Dollars)
Cash provided by (used in) financing activities
Continuing operations		$	(422	)		$	111		$	(111	)
Total		$	(422	)		$	111		$	(111	)

Cash flow from financing activities related to continuing operations decreased $533 million during 2006 due to increased net repayments of short-term borrowings in 2006 compared to 2005.

Cash flow from financing activities related to continuing operations increased $222 million during 2005 primarily due to increased short-term borrowings.

See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.

Capital Requirements

Utility Capital Expenditures and Long-Term Debt Obligations — The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2007 through 2011 are shown in the tables below.

By Segment	2007			2008			2009			2010			2011
	(Millions of Dollars)
Electric utility		$	1,723		$	1,692		$	1,466		$	1,623		$	1,503
Natural gas utility		117			141			165			139			121
Common utility and other		60			67			69			88			76
Total capital expenditures		1,900			1,900			1,700			1,850			1,700
Debt maturities		336			632			558			783			52
Total capital requirements		$	2,236		$	2,532		$	2,258		$	2,633		$	1,752

By Utility Subsidiary	2007			2008			2009			2010			2011
	(Millions of Dollars)
NSP-Minnesota		$	995		$	1,050		$	1,000		$	1,090		$	995
NSP-Wisconsin		75			85			55			60			65
PSCo		690			635			515			580			490
SPS		140			130			130			120			150
Total		$	1,900		$	1,900		$	1,700		$	1,850		$	1,700

By Project	2007			2008			2009			2010			2011
	(Millions of Dollars)
Base and other capital expenditures		$	955		$	950		$	950		$	1,000		$	965
MERP		275			170			35			10			—
Comanche 3		345			275			55			15			—
Minnesota wind transmission		150			20			50			15			—
Minnesota wind generation		50			155			—			—			—
CapX 2020 transmission		5			20			110			240			180
BART projects		—			5			40			65			40
Sherco capacity increases		10			65			200			245			165
Nuclear fuel		90			160			145			105			165
Nuclear capacity increases and life extension		20			80			115			155			185
Total		$	1,900		$	1,900		$	1,700		$	1,850		$	1,700

Many of the states in which Xcel Energy has operations are considering renewable portfolio standards, which would require significant increases in investment in renewable generation and transmission. Xcel Energy would generally be able to meet these standards by either purchasing renewable power from an independent party or by owning the assets. Therefore, these standards may present Xcel Energy with the opportunity to increase its investment in wind generation and transmission assets. As a result, Xcel Energy’s capital expenditure forecast, as detailed above, may increase due to the potential increased investments for wind generation, IGCC and transmission assets.

The capital expenditure programs of Xcel Energy 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 and approvals, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future environmental requirements and renewable portfolio standards to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2006. See additional discussion in the Consolidated Statements of Capitalization and Notes 3, 4, and 14 to the Consolidated Financial Statements.

	Payments Due by Period
	Total			Less than 1 Year			1 to 3 Years			4 to 5 Years			After 5 Years
	(Thousands of Dollars)
Long-term debt, principal and interest payments		$	11,883,096		$	759,539		$	1,943,750		$	1,451,972		$	7,727,835
Capital lease obligations		92,237			6,286			12,123			11,463			62,365
Operating leases(a)		811,899			57,405			106,693			101,485			546,316
Unconditional purchase obligations(b)		13,533,315			2,239,536			3,224,813			2,491,245			5,577,721
Other long-term obligations — WYCO investment		145,000			47,000			98,000			—			—
Other long-term obligations		202,045			25,388			47,579			46,116			82,962
Payments to vendors in process		113,183			113,183			—			—			—
Short-term debt		626,300			626,300			—			—			—
Total contractual cash obligations(c)		$	27,407,075		$	3,874,637		$	5,432,958		$	4,102,281		$	13,997,199

(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2006, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $186.1 million. In addition, at the end of the equipment leases’ terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value or equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.

(b) Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. Additionally, the utility subsidiaries of Xcel Energy have 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. Certain contractual purchase obligations are adjusted based on indices. However, the effects of price changes are mitigated through cost-of-energy adjustment mechanisms.

(c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $1.3 billion of goods and services through the year 2021, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors. Xcel Energy’s objective is to increase the annual dividend in the range of 2 percent to 4 percent per year. Xcel Energy’s dividend policy balances:

· Projected cash generation from utility operations;

· Projected capital investment in the utility businesses;

· A reasonable rate of return on shareholder investment; and

· The impact on Xcel Energy’s capital structure and credit ratings.

In addition, there are certain statutory limitations that could affect dividend levels. Federal law places certain limits on the ability of public utilities within a holding company system to declare dividends.

Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from its utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent. Some utility subsidiaries must comply with bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus surplus, divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio at Dec. 31, 2006, was 81 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends.

Capital Sources

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, preferred securities and hybrid securities to maintain desired capitalization ratios.

Short-Term Funding Sources — Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures and working capital. Another significant short-term funding need is the dividend payment.

As of Feb. 20, 2007, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

	Facility		Drawn*		Available		Cash		Liquidity		Maturity
	(Millions of Dollars)
NSP-Minnesota	$	500	$	178.5	$	321.5	$	1.1	$	322.6	December 2011
PSCo	700		237.0		463.0		1.3		464.3		December 2011
SPS	250		37.7		212.3		1.1		213.4		December 2011
Xcel Energy — holding company	800		133.7		666.3		2.1		668.4		December 2011
Total	$	2,250	$	586.9	$	1,663.1	$	5.6	$	1,668.7

* Includes outstanding commercial paper and letters of credit.

Operating cash flow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including rate recovery of costs; environmental regulation compliance; changes in the trends for energy prices; and supply and operational uncertainties, all of which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.

Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 3 to the Consolidated Financial Statements. Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reflect the views of Moody’s, Standard & Poor’s, and Fitch. A security rating is not a recommendation to buy, sell or hold securities, and is subject to revision or withdrawal at any time by the rating agency. As of Feb. 20, 2007, the following represents the credit ratings assigned to various Xcel Energy companies:

Company	Credit Type	Moody’s	Standard & Poor’s	Fitch
Xcel Energy	Senior Unsecured Debt	Baa1	BBB-	BBB+
Xcel Energy	Commercial Paper	P-2	A-2	F2
NSP-Minnesota	Senior Unsecured Debt	A3	BBB-	A
NSP-Minnesota	Senior Secured Debt	A2	A-	A+
NSP-Minnesota	Commercial Paper	P-2	A-2	F1
NSP-Wisconsin	Senior Unsecured Debt	A3	BBB	A
NSP-Wisconsin	Senior Secured Debt	A2	A-	A+
PSCo	Senior Unsecured Debt	Baa1	BBB-	BBB+
PSCo	Senior Secured Debt	A3	A-	A-
PSCo	Commercial Paper	P-2	A-2	F2
SPS	Senior Unsecured Debt	Baa1	BBB	A-
SPS	Commercial Paper	P-2	A-2	F2

Note: Moody’s highest credit rating for debt is Aaa and lowest investment grade rating is Baa3. Both Standard & Poor’s and Fitch’s highest credit rating for debt are AAA and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P-1 to P-3. Standard & Poor’s ratings for commercial paper range from A-1 to A-3. Fitch’s ratings for commercial paper range from F1 to F3.

In the event of a downgrade of its credit ratings to 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 all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 12 to the Consolidated Financial Statements. Xcel Energy has no explicit credit rating requirements in its debt agreements.

Money Pool — Xcel Energy received SEC and the FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. 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. NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. Borrowing limits are $250 million, $250 million and $100 million, respectively. No borrowings or loans were outstanding at Dec. 31, 2006.

Registration Statements — Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2006, Xcel Energy had approximately 407 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2006, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:

· Xcel Energy has $700 million available under its currently effective registration statement.

· NSP-Minnesota has $390 million available under its currently effective registration statement.

· PSCo has approximately $225 million available under its currently effective registration statement.

Future Financing Plans

To facilitate potential long-term debt issuances at the utility subsidiaries, PSCo intends to file a long-term debt shelf registration statement with the SEC in 2007, and NSP-Wisconsin may file a long-term debt shelf registration for up to $125 million.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance

Xcel Energy’s 2007 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

	2007 Diluted Earnings Per Share Range
Utility operations		$	1.39 - $1.499
COLI tax benefit		0.11
Holding company financing costs and other		(0.15		)
Xcel Energy Continuing Operations		$	1.35 - $1.455

Key Assumptions for 2007:

· Normal weather patterns are experienced during the year;

· Reasonable rate recovery is approved in the SPS Texas electric rate case;

· No material incremental accruals related to the SPS regulatory proceedings;

· Reasonable rate recovery in the Minnesota and Colorado natural gas rate cases;

· Weather-adjusted retail electric utility sales grow by approximately 1.7 percent to 2.2 percent;

· Weather-adjusted retail natural gas utility sales decline by approximately 1.0 percent to 2.0 percent;

· Short-term wholesale and commodity trading margins are within a range of $15 million to $25 million;

· Capacity costs at NSP-Minnesota and SPS are projected to increase approximately $35 million. Capacity costs at PSCo are expected to be recovered under the PCCA;

· Utility operating and maintenance expenses increase between 2 percent and 3 percent;

· Depreciation expense increases approximately $45 million to $55 million;

· Interest expense increases approximately $30 million to $35 million;

· Allowance for funds used during construction-equity increases approximately $17 million to $23 million;

· Xcel Energy continues to recognize COLI tax benefits, which is currently being litigated with the IRS;

· The effective tax rate for continuing operations is approximately 28 percent to 31 percent; and

· Average common stock and equivalents total approximately 433 million shares.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

See Management’s Discussion and Analysis under Item 7, incorporated by reference.

Item 8 — Financial Statements and Supplementary Data

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

See Note 18 of Notes to Consolidated Financial Statements for summarized quarterly financial data.

Management Report on Internal Controls Over Financial Reporting

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

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

Xcel Energy management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2006. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2006, the company’s internal control over financial reporting is effective based on those criteria.

Xcel Energy’s independent auditors have issued an audit report on our assessment of the company’s internal control over financial reporting. Their report appears on the following page.

/S/ RICHARD C. KELLY		/S/ BENJAMIN G.S. FOWKE III
Richard C. Kelly		Benjamin G.S. Fowke III
Chairman, President and Chief Executive Officer		Vice President and Chief Financial Officer
February 22, 2007		February 22, 2007

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited management’s assessment, included in the accompanying Management Report on Internal Controls Over Financial Reporting, that Xcel Energy Inc. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2006 of the Company and our report dated February 22, 2007, expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of a new accounting standard.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 22, 2007

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of income, common stockholders’ 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 schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc. 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 schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

As discussed in Note 9 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2007

F-2

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Statements of Income

(thousands, except per share data)

	Year ended Dec. 31
	2006				2005				2004
Operating revenues
Electric utility		$	7,608,018			$	7,243,637			$	6,225,245
Natural gas utility		2,155,999				2,307,385				1,915,514
Nonregulated and other		76,287				74,455				74,802
Total operating revenues		9,840,304				9,625,477				8,215,561
Operating expenses
Electric fuel and purchased power — utility		4,103,055				3,922,163				3,040,759
Cost of natural gas sold and transported — utility		1,644,716				1,823,123				1,445,773
Cost of sales — nonregulated and other		24,388				24,676				28,757
Other operating and maintenance expenses — utility		1,743,457				1,679,172				1,591,718
Other operating and maintenance expenses — nonregulated		30,069				28,493				44,109
Depreciation and amortization		821,898				767,321				705,955
Taxes (other than income taxes)		295,727				287,810				282,775
Total operating expenses		8,663,310				8,532,758				7,139,846
Operating income		1,176,994				1,092,719				1,075,715
Interest and other income net (see Note 10)		4,085				857				9,316
Allowance for funds used during construction — equity		25,045				21,627				33,648
Interest charges and financing costs
Interest charges — (includes other financing costs of $24,187, $25,829 and $27,296, respectively)		486,967				463,370				458,294
Allowance for funds used during construction — debt		(30,935		)		(20,744		)		(23,814		)
Total interest charges and financing costs		456,032				442,626				434,480
Income from continuing operations before income taxes		750,092				672,577				684,199
Income taxes		181,411				173,539				161,935
Income from continuing operations		568,681				499,038				522,264
Income (loss) from discontinued operations — net of tax (see Note 2)		3,073				13,934				(166,303		)
Net income		571,754				512,972				355,961
Dividend requirements on preferred stock		4,241				4,241				4,241
Earnings available to common shareholders		$	567,513			$	508,731			$	351,720
Weighted average common shares outstanding
Basic		405,689				402,330				399,456
Diluted		429,605				425,671				423,334
Earnings (loss) per share — basic
Income from continuing operations		$	1.39			$	1.23			$	1.30
Income (loss) from discontinued operations (see Note 2)		0.01				0.03				(0.42		)
Earnings per share		$	1.40			$	1.26			$	0.88
Earnings (loss) per share — diluted
Income from continuing operations		$	1.35			$	1.20			$	1.26
Income (loss) from discontinued operations (see Note 2)		0.01				0.03				(0.39		)
Earnings per share		$	1.36			$	1.23			$	0.87

See Notes to Consolidated Financial Statements.

F-3

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(thousands of dollars)

	Year ended Dec. 31
	2006				2005				2004
Operating activities
Net income		$	571,754			$	512,972			$	355,961
Remove (income) loss from discontinued operations		(3,073		)		(13,934		)		166,303
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		857,129				782,074				739,025
Nuclear fuel amortization		47,531				45,330				43,296
Deferred income taxes		(59,843		)		205,058				57,273
Amortization of investment tax credits		(9,806		)		(11,620		)		(12,189		)
Allowance for equity funds used during construction		(25,045		)		(21,627		)		(33,648		)
Undistributed equity in earnings of unconsolidated affiliates		(2,775		)		(712		)		(3,342		)
Gain or write down of assets sold or held for sale		(6,189		)		2,887				—
Unrealized gain (loss) on derivative instruments		(6,240		)		(3,923		)		6,206
Settlement of interest rate swap		(8,002		)		—				—
Change in accounts receivable		176,732				(250,305		)		(123,044		)
Change in inventories		28,967				(94,605		)		(46,220		)
Change in other current assets		212,532				(289,250		)		(190,827		)
Change in accounts payable		(105,707		)		281,430				133,278
Change in other current liabilities		135,456				30,923				2,494
Change in other noncurrent assets		(41,290		)		(67,138		)		17,025
Change in other noncurrent liabilities		(33,390		)		22,874				16,159
Operating cash flows (used in) provided by discontinued operations		195,255				53,283				(314,575		)
Net cash provided by operating activities		1,923,996				1,183,717				813,175
Investing activities
Utility capital/construction expenditures		(1,626,000		)		(1,304,468		)		(1,274,290		)
Allowance for equity funds used during construction		25,045				21,627				33,648
Purchase of investments in external decommissioning fund		(1,288,103		)		(576,001		)		(305,328		)
Proceeds from the sale of investments in external decommissioning fund		1,240,034				494,529				228,676
Nonregulated capital expenditures and asset acquisitions		(1,620		)		(6,976		)		(2,122		)
Proceeds from sale of assets		24,670				11,228				—
Change in restricted cash		11,813				(6,226		)		42,628
Other investments		13,535				5,075				8,392
Investing cash flows provided by discontinued operations		50,516				135,577				37,119
Net cash used in investing activities		(1,550,110		)		(1,225,635		)		(1,231,277		)
Financing activities
Short-term borrowings — net		(119,820		)		433,820				253,737
Proceeds from issuance of long-term debt		1,326,180				2,529,408				419,848
Repayment of long-term debt, including reacquisition premiums		(1,285,584		)		(2,517,698		)		(438,595		)
Proceeds from issuance of common stock		16,275				9,085				6,985
Repurchase of common stock		—				—				(32,023		)
Dividends paid		(358,746		)		(343,092		)		(320,444		)
Financing cash flows used in discontinued operations		—				(200		)		(200		)
Net cash (used in) provided by financing activities		(421,695		)		111,323				(110,692		)
Net increase (decrease) in cash and cash equivalents		(47,809		)		69,405				(528,794		)
Net increase (decrease) in cash and cash equivalents — discontinued operations		13,071				(20,570		)		(12,018		)
Net increase in cash and cash equivalents — adoption of FIN No. 46		—				—				3,439
Cash and cash equivalents at beginning of year		72,196				23,361				560,734
Cash and cash equivalents at end of year		$	37,458			$	72,196			$	23,361
Supplemental disclosure of cash flow information
Cash paid for interest (net of amounts capitalized)		$	427,683			$	417,016			$	423,673
Cash paid for income taxes (net of refunds received)		$	(13,329	)		$	10,625			$	(355,639	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable		$	54,102			$	42,526			$	48,306
Supplemental disclosure of non-cash financing transactions:
Issuance of common stock for reinvested dividends and 401(k) plans		$	56,194			$	43,882			$	854

See Notes to Consolidated Financial Statements.

F-4

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Balance Sheets

(thousands of dollars)

	Dec. 31
	2006				2005
Assets
Current assets:
Cash and cash equivalents		$	37,458			$	72,196
Accounts receivable — net of allowance for bad debts: $36,689 and $39,798, respectively		833,293				1,011,569
Accrued unbilled revenues		514,300				614,016
Materials and supplies inventories — at average cost		158,721				159,560
Fuel inventory — at average cost		95,651				64,987
Natural gas inventories — at average cost		251,818				310,610
Recoverable purchased natural gas and electric energy costs		258,600				395,070
Derivative instruments valuation		101,562				213,138
Prepayments and other		205,743				99,904
Current assets held for sale and related to discontinued operations		177,040				200,811
Total current assets		2,634,186				3,141,861
Property, plant and equipment, at cost:
Electric utility plant		19,367,671				18,870,516
Natural gas utility plant		2,846,435				2,779,043
Common utility and other property		1,439,020				1,518,266
Construction work in progress		1,425,484				783,490
Total property, plant and equipment		25,078,610				23,951,315
Less accumulated depreciation		(9,670,104		)		(9,357,414		)
Nuclear fuel — net of accumulated amortization: $1,237,917 and $1,190,386, respectively		140,152				102,409
Net property, plant and equipment		15,548,658				14,696,310
Other assets:
Nuclear decommissioning fund and other investments		1,279,573				1,145,659
Regulatory assets		1,189,145				820,007
Derivative instruments valuation		437,520				451,937
Prepaid pension asset		586,712				683,649
Other		135,746				164,212
Noncurrent assets held for sale and related to discontinued operations		146,806				401,285
Total other assets		3,775,502				3,666,749
Total assets		$	21,958,346			$	21,504,920
Liabilities and Equity
Current liabilities:
Current portion of long-term debt		$	336,411			$	835,495
Short-term debt		626,300				746,120
Accounts payable		1,101,270				1,187,489
Taxes accrued		252,384				235,056
Dividends payable		91,685				87,788
Derivative instruments valuation		83,944				191,414
Other		347,809				345,807
Current liabilities held for sale and related to discontinued operations		25,478				43,657
Total current liabilities		2,865,281				3,672,826
Deferred credits and other liabilities:
Deferred income taxes		2,256,599				2,191,794
Deferred investment tax credits		121,594				131,400
Regulatory liabilities		1,364,657				1,567,424
Asset retirement obligations		1,361,951				1,292,006
Derivative instruments valuation		483,077				499,390
Customer advances		302,168				310,092
Pension and employee benefit obligations		704,913				326,793
Other liabilities		119,633				104,688
Noncurrent liabilities held for sale and related to discontinued operations		5,473				6,936
Total deferred credits and other liabilities		6,720,065				6,430,523
Minority interest in subsidiaries		1,560				3,547
Commitments and contingent liabilities (see Note 14)
Capitalization (see Statements of Capitalization):
Long-term debt		6,449,638				5,897,789
Preferred stockholders’ equity		104,980				104,980
Common stockholders’ equity		5,816,822				5,395,255
Total liabilities and equity		$	21,958,346			$	21,504,920

See Notes to Consolidated Financial Statements.

F-5

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Statements of Common Stockholders’ Equity
and Comprehensive Income

(thousands)

	Common Stock Issued															Accumulated
	Shares			Par Value				Additional Paid in Capital				Retained Earnings				Other Comprehensive Income (Loss)				Total Common Stockholders’ Equity
Balance at Dec. 31, 2003		398,965			$	997,412			$	3,890,501			$	368,663			$	(90,136	)		$	5,166,440
Net income													355,961								355,961
Currency translation adjustments																	(3		)		(3		)
Minimum pension liability adjustment, net of tax of $(5,414) (see Note 9)																	(7,935		)		(7,935		)
Net derivative instrument fair value changes during the period, net of tax of $(5,549) (see Note 11)																	(8,024		)		(8,024		)
Unrealized gain — marketable securities, net of tax of $77																	164				164
Comprehensive income for 2004																					340,163
Dividends declared:
Cumulative preferred stock													(4,241		)						(4,241		)
Common stock													(323,742		)						(323,742		)
Issuances of common stock		3,297			8,243				48,078												56,321
Purchases for restricted stock issuance		(1,800	)		(4,500		)		(27,523		)										(32,023		)
Balance at Dec. 31, 2004		400,462			$	1,001,155			$	3,911,056			$	396,641			$	(105,934	)		$	5,202,918
Net income													512,972								512,972
Minimum pension liability adjustment, net of tax of $(10,717) (see Note 9)																	(17,271		)		(17,271		)
Net derivative instrument fair value changes during the period, net of tax of $(5,137) (see Note 11)																	(8,919		)		(8,919		)
Unrealized gain — marketable securities, net of tax of $41																	63				63
Comprehensive income for 2005																					486,845
Dividends declared:
Cumulative preferred stock													(4,241		)						(4,241		)
Common stock													(343,234		)						(343,234		)
Issuances of common stock		2,925			7,313				45,654												52,967
Balance at Dec. 31, 2005		403,387			$	1,008,468			$	3,956,710			$	562,138			$	(132,061	)		$	5,395,255
Net income													571,754								571,754
Minimum pension liability adjustment, net of tax of $19,498 (see Note 9)																	31,957				31,957
Net derivative instrument fair value changes during the period, net of tax of $6,297 (see Note 11)																	11,000				11,000
Unrealized loss — marketable securities, net of tax of $(18)																	(26		)		(26		)
Comprehensive income for 2006																					614,685
SFAS No. 158 adoption, net of tax of $42,265																	72,804				72,804
Dividends declared:
Cumulative preferred stock													(4,241		)						(4,241		)
Common stock													(358,402		)						(358,402		)
Issuances of common stock		3,910			9,774				58,998												68,772
Share-based compensation (see Note 8)									27,949												27,949
Balance at Dec. 31, 2006		407,297			$	1,018,242			$	4,043,657			$	771,249			$	(16,326	)		$	5,816,822

See Notes to Consolidated Financial Statements.

F-6

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Statements of Capitalization

(thousands of dollars)

	Dec. 31
	2006				2005
	(Thousands of Dollars)
Long-Term Debt
NSP-Minnesota
First Mortgage Bonds, Series due:
Dec. 1, 2006, 4.1%(a)		$	—			$	2,420
Dec. 1, 2007-2008, 4.5%-4.6%(a)		—				7,490
Aug. 1, 2006, 2.875%		—				200,000
Aug. 1, 2010, 4.75%		175,000				175,000
Aug. 28, 2012, 8%		450,000				450,000
March 1, 2019, 8.5%(b)		27,900				27,900
Sept. 1, 2019, 8.5%(b)		100,000				100,000
July 1, 2025, 7.125%		250,000				250,000
March 1, 2028, 6.5%		150,000				150,000
April 1, 2030, 8.5%(b)		69,000				69,000
July 15, 2035, 5.25%		250,000				250,000
June 1, 2036, 6.25%		400,000				—
Senior Notes, due Aug. 1, 2009, 6.875%		250,000				250,000
Borrowings under credit facility, due April 2010, 5.05%		—				250,000
Retail Notes, due July 1, 2042, 8%		185,000				185,000
Other		89				519
Unamortized discount-net		(7,761		)		(7,278		)
Total		2,299,228				2,360,051
Less current maturities		40				204,833
Total NSP-Minnesota long-term debt		$	2,299,188			$	2,155,218
PSCo
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%(b)		129,500				129,500
Jan. 1, 2019, 5.1%(b)		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 PSCo long-term debt		$	1,845,278			$	1,945,973
SPS
Unsecured Senior B Notes, due Nov. 1, 2006, 5.125%		$	—			$	500,000
Unsecured Senior A Notes, due March 1, 2009, 6.2%		100,000				100,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%		100,000				100,000
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6%		200,000				—
Unsecured Senior F Notes, due Oct. 1, 2036, 6%		250,000				—
Pollution control obligations, securing pollution control revenue bonds, due:
July 1, 2011, 5.2%		44,500				44,500
July 1, 2016, 3.95% at Dec. 31, 2006, and 3.58% at Dec. 31, 2005		25,000				25,000
Sept. 1, 2016, 5.75%		57,300				57,300
Unamortized discount		(2,897		)		(1,024		)
Total		773,903				825,776
Less current maturities		—				500,000
Total SPS long-term debt		$	773,903			$	325,776

See Notes to Consolidated Financial Statements.

F-7

XCEL ENERGY INC. AND SUBSIDIARIES

Consolidated Statements of Capitalization — (Continued)

(thousands of dollars)

	Dec. 31
	2006				2005
	(Thousands of Dollars)
Long-Term Debt — continued
NSP-Wisconsin
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25%		$	150,000			$	150,000
Dec. 1, 2026, 7.375%		65,000				65,000
Senior Notes due, Oct. 1, 2008, 7.64%		80,000				80,000
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6%(a)		18,600				18,600
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%		794				828
Unamortized discount		(852		)		(919		)
Total		313,542				313,509
Less current maturities		34				34
Total NSP-Wisconsin long-term debt		$	313,508			$	313,475
Other Subsidiaries
Various Eloigne Co. Affordable Housing Project Notes, due 2007-2045, 0% — 9.89%		$	90,910			$	95,692
Other		2,122				2,217
Total		93,032				97,909
Less current maturities		4,958				4,294
Total other subsidiaries long-term debt		$	88,074			$	93,615
Xcel Energy Inc.
Unsecured senior notes, Series due:
July 1, 2008, 3.4%		$	195,000			$	195,000
Dec. 1, 2010, 7%		600,000				600,000
July 1, 2036, 6.5%		300,000				—
Convertible notes, Series due:
Nov. 21, 2007, 7.5%		230,000				230,000
Nov. 21, 2008, 7.5%		57,500				57,500
Fair value hedge, carrying value adjustment		(17,786		)		(14,073		)
Unamortized discount		(5,027		)		(4,695		)
Total		1,359,687				1,063,732
Less current maturities		230,000				—
Total Xcel Energy Inc. debt		$	1,129,687			$	1,063,732
Total long-term debt		$	6,449,638			$	5,897,789
Preferred Stockholders’ Equity
Preferred Stock — authorized 7,000,000 shares of $100 par value; outstanding shares: 2006: 1,049,800; 2005: 1,049,800
$3.60 series, 275,000 shares		$	27,500			$	27,500
$4.08 series, 150,000 shares		15,000				15,000
$4.10 series, 175,000 shares		17,500				17,500
$4.11 series, 200,000 shares		20,000				20,000
$4.16 series, 99,800 shares		9,980				9,980
$4.56 series, 150,000 shares		15,000				15,000
Total preferred stockholders’ equity		$	104,980			$	104,980
Common Stockholders’ Equity
Common stock — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2006: 407,296,907; 2005: 403,387,159		$	1,018,242			$	1,008,468
Additional paid in capital		4,043,657				3,956,710
Retained earnings		771,249				562,138
Accumulated other comprehensive loss		(16,326		)		(132,061		)
Total common stockholders’ equity		$	5,816,822			$	5,395,255

(a) Resource recovery financing

(b) Pollution control financing

See Notes to Consolidated Financial Statements.

F-8

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

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

Principles of Consolidation — In 2006, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 8 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline, and WYCO, a natural gas pipeline and storage company in Colorado, these companies comprise our continuing regulated utility operations.

Xcel Energy’s nonregulated subsidiary in continuing operations is Eloigne (investments in rental housing projects that qualify for low-income housing reported tax credits). Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O&M Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy in the past had several other subsidiaries, which were sold or divested. For more information, see Note 2 to the Consolidated Financial Statements.

In 2004, Xcel Energy began consolidating the financial statements of subsidiaries in which it has a controlling financial interest, pursuant to the requirements of FIN No. 46. Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. As a result, Xcel Energy is required to consolidate a portion of its affordable housing investments made through Eloigne. As of Dec. 31, 2006, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $134 million and long-term liabilities were approximately $77 million, including long-term debt of $70 million. Investments of $51 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.

Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects for which it does not have a controlling financial interest. Under this method, a proportionate share of pretax income is recorded as equity earnings from investments in affiliates. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis, consistent with industry practice. See Note 6 to the Consolidated Financial Statements.

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

Xcel Energy’s utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, 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, Xcel Energy presents its revenue net of any excise or other fiduciary-type taxes or fees. A summary of significant rate-adjustment mechanisms follows:

· NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.

F-9

The electric cost-of-fuel-and-purchased-energy mechanism also provides a sharing among shareholders and customers of certain margins on short-term wholesale sales and commodity trading.

· NSP-Wisconsin’s rates include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. In Wisconsin, requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel-cost hearing process.

· 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 Texas, SPS may request periodic adjustments to provide electric fuel and purchased energy cost recovery. In New Mexico, SPS has a monthly fuel and purchased power cost-recovery factor.

· In Colorado, PSCo operates under an annual earnings test in which earnings above the authorized return on equity are refunded to customers. NSP-Minnesota and PSCo operate under various service quality standards in Minnesota and Colorado, respectively, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s rates in Minnesota and Colorado, respectively, 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. NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities to deliver renewable energy resources through a rate rider.

· NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell 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.

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with SFAS No. 133. In addition, commodity trading results include the impact of all pertinent margin-sharing mechanisms.

Derivative Financial Instruments — Xcel Energy and its subsidiaries utilize a variety of derivatives, including commodity forwards, futures and options, index or fixed price swaps and basis swaps, to reduce exposure to commodity price and interest rate risks and to enhance its operations. For further discussion of Xcel Energy’s risk management and derivative activities, see Note 11 to the Consolidated Financial Statements.

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

Xcel Energy 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, was approximately 3.2 percent, 3.2 percent and 3.1 percent for the years ended Dec. 31, 2006, 2005 and 2004, respectively.

F-10

AFDC — AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.

Generally, AFDC costs are recovered from customers as the related property is depreciated. In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. The MPUC has approved a more current recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.

Decommissioning — Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses are included with Regulatory assets on the Consolidated Balance Sheets. For more information on nuclear decommissioning, see Note 15 to the Consolidated Financial Statements.

Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as the nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFDC), as well as future disposal costs of spent nuclear fuel, costs associated with the end-of-life fuel segments, and fees assessed by the DOE for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel-enrichment facility.

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

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy’s expected share of the cost is estimated and recorded. 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 domestic subsidiaries file consolidated federal income tax returns. Xcel Energy and its domestic subsidiaries file combined and separate state income tax returns.

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

Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. 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 7 to the Consolidated Financial Statements.

F-11

Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy 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 becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

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

Inventory — All inventory is recorded at average cost.

Regulatory Accounting — Our regulated utility subsidiaries account 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.

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, our regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s results of operations in the period the write-offs are recorded. See more discussion of regulatory assets and liabilities at Note 16 to the Consolidated Financial Statements.

Deferred Financing Costs — Other assets included deferred financing costs, net of amortization, of approximately $47 million and $42 million at Dec. 31, 2006 and 2005, respectively. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt.

Accounts Receivable and Allowance for Uncollectibles — Accounts receivable are stated at the actual billed amount net of write-offs and allowance for uncollectibles. Xcel Energy 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. Xcel Energy 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 Electric Utility Operations Revenue as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

Reclassifications — The balance sheet and the statements of cash flows have been reclassified from prior-period presentation to conform to the 2006 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were related to the presentation of regulatory assets and liabilities for ARO and decommissioning activities on a net basis. These reclassifications did not affect total operating, investing or financing within the statements of cash flows.

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 would be reflected as a component of income tax expense.

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

F-12

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. Xcel Energy 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. Discontinued Operations

Xcel Energy classified and accounted for certain assets as held for sale at Dec. 31, 2006 and 2005. Assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. Assets held for sale are not depreciated.

Results of operations for divested businesses and the results of businesses held for sale are reported for all periods presented on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2006 and 2005 have been reclassified to assets and liabilities held for sale in the accompanying Balance Sheet.

Regulated Utility Subsidiaries

In 2005, Black Hills Corp. purchased all the common stock of Cheyenne, including the assumption of outstanding debt of approximately $25 million, for approximately $90 million, plus a working capital adjustment finalized in 2005. The sale resulted in an after-tax loss of approximately $13 million, or 3 cents per share.

Nonregulated Subsidiaries

Utility Engineering — In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an insignificant loss in the first quarter of 2005 as a result of the transaction. The majority of Quixx Corp., including Borger Energy Associates and Quixx Power Services, Inc., was sold in October 2006 to affiliates of Energy Investors Funds.

Seren — In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings, LLC. In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communications. An estimated after-tax impairment charge, including disposition costs, of $143 million, or 34 cents per share, was recorded in 2004. Based on the sales agreements entered into in 2005, the estimate was adjusted in 2005 to reflect a total asset impairment of $140 million.

Xcel Energy International and e prime — The exit of all business conducted by e prime was completed in 2004. The results of discontinued nonregulated operations in 2004 include the impact of the sale of the Argentina subsidiaries of Xcel Energy International, for a sales price of approximately $31 million. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including the realization of approximately $7 million of income tax benefits realizable upon the sale of the Xcel Energy International assets.

NRG — With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership interest in NRG. Xcel Energy recognized $13 million tax expense and $17 million tax benefit related to the divestiture of NRG in 2004 and 2005, respectively. These tax expenses and benefits are reported as discontinued operations.

F-13

Summarized Financial Results of Discontinued Operations

	Utility Segment				All Other Segment				Total
	(Thousands of Dollars)
2006
Operating revenue		$	—			$	7,525			$	7,525
Operating and other expenses		278				9,011				9,289
Pretax loss from operations of discontinued components		(278		)		(1,486		)		(1,764		)
Income tax benefit		(3,291		)		(1,546		)		(4,837		)
Income from operations of discontinued components		3,013				60				3,073
Net income from discontinued operations		$	3,013			$	60			$	3,073
2005					��
Operating revenue		$	6,579			$	63,206			$	69,785
Operating and other expenses		6,131				68,669				74,800
Pretax income (loss) from operations of discontinued components		448				(5,463		)		(5,015		)
Income tax expense (benefit)		268				(19,217		)		(18,949		)
Income from operations of discontinued components		180				13,754				13,934
Net income from discontinued operations		$	180			$	13,754			$	13,934
2004
Operating revenue		$	72,232			$	179,890			$	252,122
Operating and other expenses		68,305				194,605				262,910
Special charges and impairments		6,574				228,439				235,013
Pretax loss from operations of discontinued components		(2,647		)		(243,154		)		(245,801		)
Income tax expense (benefit)		6,388				(78,021		)		(71,633		)
Loss from operations of discontinued components		(9,035		)		(165,133		)		(174,168		)
Estimated pretax gain on disposal of discontinued components		—				961				961
Income tax benefit		—				6,904				6,904
Gain on disposal of discontinued components		—				7,865				7,865
Net loss from discontinued operations		$	(9,035	)		$	(157,268	)		$	(166,303	)

The major classes of assets and liabilities held for sale and related to discontinued operations as of Dec. 31 are as follows:

	2006			2005
	(Thousands of Dollars)
Cash		$	25,729		$	12,658
Trade receivables — net		421			6,101
Deferred income tax benefits		144,740			157,812
Other current assets		6,150			24,240
Current assets		177,040			200,811
Property, plant and equipment — net		174			29,845
Deferred income tax benefits		144,564			352,171
Other noncurrent assets		2,068			19,269
Noncurrent assets		146,806			401,285
Accounts payable — trade		1,560			7,657
Other current liabilities		23,918			36,000
Current liabilities		25,478			43,657
Other noncurrent liabilities		5,473			6,936
Noncurrent liabilities		$	5,473		$	6,936

3. Short-Term Borrowings

Commercial Paper — At Dec. 31, 2006 and 2005, Xcel Energy and its utility subsidiaries had commercial paper outstanding of approximately $626.3 million and $746.1 million, respectively. The weighted average interest rates at Dec. 31, 2006 and 2005 were 5.47 percent and 4.46 percent, respectively.

F-14

4. Long-Term Debt

Credit Facilities — At Dec. 31, 2006, Xcel Energy and its utility subsidiaries had the following committed credit facilities available:

	Credit Facility			Credit Facility Borrowings			Available*			Term		Maturity
	(Millions of Dollars)
NSP-Minnesota		$	500		$	—		$	376.5		Five year	December 2011
PSCo		700			—			321.5			Five year	December 2011
SPS		250			—			197.3			Five year	December 2011
Xcel Energy — holding company		800			—			685.5			Five year	December 2011
Total		$	2,250		$	—		$	1,580.8

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

The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Each credit facility has one financial covenant requiring that the debt-to-total-capitalization ratio of each entity be less than or equal to 65 percent with which all were in compliance. The interest rates under these lines of credit are based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin based on the applicable debt rating.

Xcel Energy has an $800 million, five-year senior unsecured revolving credit facility that matures in December 2011. Xcel Energy 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. As of Dec. 31, 2006, Xcel Energy had no direct borrowings on this line of credit, however the credit facility was used to provide backup for $113.8 million of commercial paper outstanding and $0.7 million of letters of credit. As discussed in Note 12 to the Consolidated Financial Statements, $43.8 million of letters of credit were outstanding at Dec. 31, 2006, of which $0.7 million were supported by the Xcel Energy credit facility and are included in the above table.

Xcel Energy’s 2007 and 2008 series convertible senior notes are convertible into shares of Xcel Energy common stock at a conversion price of $12.33 per share. Conversion is at the option of the holder at any time prior to maturity. In addition, Xcel Energy must make additional payments of interest, referred to as protection payments, on the notes in an amount equal to any portion of regular quarterly per share dividends on common stock that exceeds 18.75 cents per share that would have been payable to the holders of the notes if such holders had converted their notes on the record date for such dividend. On May 17, 2006, the board of directors of Xcel Energy voted to raise the quarterly dividend on its common stock from 21.50 cents per share to 22.25 cents per share. Consequently, as of Dec. 31, 2006, a total of $3.1 million in additional interest expense has been recorded.

All property of NSP-Minnesota and NSP-Wisconsin and the electric property of PSCo are subject to the liens of their first mortgage indentures. In addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas.

Maturities of long-term debt are:

	(Millions of Dollars)
2007		$	336.4
2008		$	631.8
2009		$	557.7
2010		$	782.9
2011		$	51.5

5. Preferred Stock

Xcel Energy has authorized 7,000,000 shares of preferred stock with a $100 par value. At Dec. 31, 2006, Xcel Energy had six series of preferred stock outstanding, redeemable at its option at prices ranging from $102.00 to $103.75 per share plus accrued dividends.

The holders of the $3.60 series preferred stock are entitled to three votes per each share held. The holders of the other series of preferred stock are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are

F-15

entitled to elect the smallest number of directors necessary to constitute a majority of the board of directors. The holders of common stock, voting as a class, are entitled to elect the remaining directors.

The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred stock. However, at Dec. 31, 2006, there are no preferred shares of subsidiaries outstanding.

	Preferred Shares Authorized		Par Value			Preferred Shares Outstanding
SPS		10,000,000		$	1.00		None
PSCo		10,000,000		$	0.01		None

6. Generating Plant Ownership and Operation

Joint Plant Ownership — Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2006:

	Plant in Service			Accumulated Depreciation			Construction Work in Progress			Ownership%
	(Thousands of Dollars)
NSP-Minnesota
Sherco Unit 3		$	496,188		$	293,906		$	2,130		59.0
Sherco Common Facilities Units 1, 2 and 3		106,939			57,800			2,292			75.0
Transmission facilities, including substations		4,832			2,004			—			59.0
Total NSP-Minnesota		$	607,959		$	353,710		$	4,422
PSCo
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 PSCo		$	421,273		$	186,269		$	217,599

NSP-Minnesota is part owner of Sherco 3, an 860-MW, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for funding its portion of the construction costs. For Sherco Common Facilities Units 1, 2 and 3, the ownership percentage for Xcel Energy increased from 65.6 percent to 75 percent in January 2006 on new capital investments.

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 the issuance of its own securities to finance 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.

Nuclear Plant Operation — The NMC is an operating company that manages the operations, maintenance and physical security of several nuclear generating units, including three units/two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy produced by the plants and retains responsibility for nuclear property, liability insurance, spent fuel and decommissioning costs. As of Dec. 31, 2006, all members of the NMC, other than Xcel Energy, have chosen to sell their units and exit the NMC. Regarding the remaining members of the NMC, the sales transaction of CMS Energy Corp Palisades Nuclear Power Plant is targeted to close in the first quarter of 2007. In December 2006, Wisconsin Electric Power Co., announced its intent to sell its Point Beach Nuclear Plant to FPL Energy with the sale expected to close in the third or fourth quarter of 2007.

Following consummation of the sale transactions, NSP-Minnesota will be the sole remaining member of the NMC. NSP-Minnesota is evaluating the situation. One option under consideration is to transition the NMC to a wholly owned subsidiary of Xcel Energy. To facilitate implementation of this option, Xcel Energy plans are progressing to restructure the

F-16

NMC to support a two-site organization, as well as reabsorb the administrative functions within Xcel Energy by the end of 2007

In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid the NMC $292.5 million in 2006, $257.1 million in 2005 and $314.7 million in 2004.

7. Income Taxes

Xcel Energy’s federal net operating loss and tax credit carry forwards are estimated to be $731 million and $135 million, respectively. A portion of the net operating loss in the amount of $505.9 million and a portion of the tax credit carry forward in the amount of $46.1 million are accounted for in discontinued operations. The carry forward periods expire in 2023 and 2024. Xcel Energy also has state net operating loss and tax credit carry forwards of $1.5 billion and $10 million, respectively. The state carry forward periods expire between 2014 and 2024. A valuation allowance recorded in prior years against deferred tax assets for capital loss carry forwards related to discontinued operations was reduced to zero during 2006 due to capital gains. The valuation allowance was $44 million as of Dec. 31, 2005.

Total income tax expense from continuing 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		3.0			2.5			3.3
Life insurance policies		(4.7	)		(4.6	)		(4.0	)
Tax credits recognized		(3.4	)		(4.4	)		(4.4	)
Capital loss carryforward utilization		(2.4	)		—			—
Resolution of income tax audits and other		(1.6	)		(0.3	)		(5.3	)
Regulatory differences — utility plant items		(0.5	)		(0.3	)		(0.1	)
Other — net		(1.2	)		(2.1	)		(0.8	)
Effective income tax rate from continuing operations		24.2	%		25.8	%		23.7	%

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

	2006				2005				2004
	(Thousands of Dollars)
Current federal tax expense		$	209,941			$	(4,122	)		$	88,514
Current state tax expense		41,119				(15,733		)		32,135
Current tax credits		—				(45		)		(3,798		)
Deferred federal tax expense		(37,575		)		191,900				67,716
Deferred state tax expense		(8,695		)		31,235				3,574
Deferred tax credits		(13,573		)		(18,077		)		(14,017		)
Deferred investment tax credits		(9,806		)		(11,619		)		(12,189		)
Total income tax expense from continuing operations		$	181,411			$	173,539			$	161,935

F-17

The components of Xcel Energy’s net deferred tax liability from continuing operations (current and noncurrent portions) at Dec. 31 were:

	2006			2005
	(Thousands of Dollars)
Deferred tax liabilities:
Differences between book and tax bases of property		$	2,279,184		$	2,245,748
Regulatory assets		182,354			257,843
Employee benefits		25,291			25,711
Service contracts		7,592			8,539
Partnership income/loss		4,248			10,010
Other		28,399			85,810
Total deferred tax liabilities		$	2,527,068		$	2,633,661
Deferred tax assets:
Net operating loss carry forward		$	101,608		$	119,124
Tax credit carry forward		99,025			86,143
Other comprehensive income		14,808			80,356
Deferred investment tax credits		47,517			51,286
Regulatory liabilities		41,199			40,835
Accrued liabilities and other		71,626			46,106
Total deferred tax assets		$	375,783		$	423,850
Net deferred tax liability		$	2,151,285		$	2,209,811

8. Common Stock and Stock-Based Compensation

Common Stock and Equivalents — Xcel Energy has common stock equivalents consisting of convertible senior notes, 401(k) equity awards, restricted stock units and stock options, as discussed later.

In 2006, 2005 and 2004, Xcel Energy had approximately 11.0 million, 13.3 million and 14.3 million options outstanding, respectively, that were antidilutive and, therefore, excluded from the earnings per share calculation. The dilutive impact of common stock equivalents affected earnings per share as follows for the years ending Dec. 31:

	2006							2005							2004
	Income			Shares	Per Share Amount			Income			Shares	Per Share Amount			Income			Shares	Per Share Amount
	(Shares and dollars in thousands, except per share amounts)
Income from continuing operations	$	568,681						$	499,038						$	522,264
Less: Dividend requirements on preferred stock	(4,241		)					(4,241		)					(4,241		)
Basic earnings per share
Income from continuing operations	564,440			405,689		$	1.39	494,797			402,330		$	1.23	518,023			399,456		$	1.30
Effect of dilutive securities:
$230 million convertible debt	12,090			18,654				11,498			18,654				11,940			18,654
$57.5 million convertible debt	3,022			4,663				2,875			4,663				2,985			4,663
Restricted stock units	—			—				—			—				—			544
401(k) equity awards	—			551				—			—				—			—
Options	—			48				—			24				—			17
Diluted earnings per share
Income from continuing operations and assumed conversions	$	579,552		429,605		$	1.35	$	509,170		425,671		$	1.20	$	532,948		423,334		$	1.26

Stock-Based Compensation — Xcel Energy has incentive compensation plans under which stock options and other performance incentives are awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy’s earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock method. The options normally have a term of 10 years and generally become exercisable from three to five years after grant date or upon specified circumstances.

F-18

Activity in stock options was as follows for the years ended Dec. 31:

	2006						2005						2004
(Awards in thousands)	Awards			Average Price			Awards			Average Price			Awards			Average Price
Outstanding beginning of year		13,576			$	26.92		14,606			$	26.67		15,614			$	26.49
Exercised		(563	)		18.33			(152	)		17.30			(45	)		15.08
Forfeited		(89	)		26.98			(213	)		26.84			(172	)		25.10
Expired		(550	)		25.66			(665	)		23.71			(791	)		24.08
Outstanding at end of year		12,374			$	27.36		13,576			$	26.92		14,606			$	26.67
Exercisable at end of year		12,374			$	27.36		13,529			$	26.91		10,096			$	26.58

	Range of Exercise Prices
	$15.94 to $26.00			$26.01 to $30.00			$30.01 to $51.25
Options outstanding and exercisable:
Number outstanding and exercisable		3,761,931			6,865,031			1,747,251
Weighted average remaining contractual life (years)		3.8			3.1			2.7
Weighted average exercise price		$	23.44		$	27.02		$	37.16

Certain employees also may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan. Restricted stock vests in equal annual installments over a three-year period from the date of grant. Xcel Energy reinvests dividends on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. Restricted stock has a value equal to the market-trading price of Xcel Energy’s stock at the grant date. Xcel Energy granted 10,481 shares of restricted stock in 2006 when the grant-date market price was $19.10. Xcel Energy granted 28,626 shares of restricted stock in 2005 when the grant-date market price was $17.81. Xcel Energy granted 65,090 shares of restricted stock in 2004 when the grant-date market price was $17.40. Compensation expense related to these awards was not material.

On March 28, 2003, Xcel Energy’s board of directors granted restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan approved by the shareholders in 2000. Restrictions on the restricted stock units lapse upon the achievement of a 27-percent total shareholder return (TSR) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. Under no circumstances will the restrictions lapse until one year after the grant date. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. The performance share award is entirely dependent on a single measure, the TSR. Xcel Energy’s TSR is measured over a three-year period. Xcel Energy’s TSR is compared to the TSR of other companies in the Edison Electric Institute’s Electrics Index. At the end of the three-year period, potential payouts of the performance shares range from 0 percent to 200 percent, depending on Xcel Energy’s TSR compared to the peer group. The 2003 performance share award met the TSR as of Dec. 31, 2005. Approximately 0.4 million shares were issued in February 2006 after approximately 0.3 million shares were withheld for tax purposes and $8 million was settled in cash.

The TSR related to the restricted stock units was met in the fourth quarter of 2003, and approximately $31 million of compensation expense was recorded at Dec. 31, 2003. The remaining cost of $10 million related to the 2003 restricted stock units was recorded in the first quarter of 2004. In January 2004, Xcel Energy’s board of directors approved the repurchase of up to 2.5 million shares of common stock to fulfill the requirements of the restricted stock unit exercise. On March 29, 2004, the restrictions lapsed on the restricted stock units, and Xcel Energy issued approximately 1.6 million shares of common stock after approximately 0.9 million shares were withheld for tax purposes.

On Jan. 2, 2004, Xcel Energy granted 836,186 restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. The grant-date market price used to calculate the TSR for this grant is $17.03. On Aug. 2, 2006, the restrictions lapsed on the restricted stock units, and Xcel Energy issued approximately 0.4 million shares of common stock after approximately 0.2 million shares were withheld for tax purposes. The 2004 performance share award met the TSR as of Dec. 31, 2006 and will be settled in shares and cash in February 2007.

On Jan. 1, 2005, Xcel Energy granted 519,362 restricted stock units and 323,889 performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. Payout of the units and the lapsing of restrictions on the transfer of units are based on two separate performance criteria. A portion of the awarded units plus associated earned dividend equivalents will be settled, and the restricted period will lapse after Xcel Energy achieves a specified earnings per share growth (adjusted for corporate-owned life insurance) measured against year-end earnings per share (adjusted for corporate-owned life insurance). Additionally, Xcel Energy’s annual dividend paid on its common stock must remain at $0.83 per share or greater. Earnings per share growth will be measured annually at the end of each fiscal year. However, in no event will the restrictions lapse

F-19

prior to two years after the date of grant. The remaining awarded units plus associated earned dividend equivalents will be settled, and the restricted period will lapse after the average of actual performance results (adjusted for actual MW hours) for the three components of an environmental index measured as a percentage of target performance meets or exceeds 100 percent. The environmental index will be measured annually at the end of each fiscal year. However, in no event will the restrictions lapse prior to two years after the date of grant. If the performance criteria have not been met within four years of the date of grant, all associated units shall be forfeited. The 2005 environmental restricted stock units met their target as of Dec. 31, 2006 and will be settled in shares in February 2007.

Xcel Energy granted approximately 542,000 and 653,000 restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan in 2007 and 2006, respectively.

SFAS No. 123 (Revised 2004) — “Share Based Payment” (SFAS No. 123R) — In December 2004, the FASB issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 — “Accounting for Stock-Based Compensation.” Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment awards using the intrinsic value method, which did not require any expense to be recorded on stock options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at least six factors identified in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs.

Previous accounting guidance allowed for compensation expense related to share-based payment awards to be reversed if the target was not met. However, under SFAS No. 123R, compensation expense for share-based payment awards that expire unexercised due to the company’s failure to reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit award that was granted in 2004 and is based on a total shareholder return (TSR) cannot be reversed if the target is not met. As required, Xcel Energy adopted the provisions in the first quarter of 2006 using the modified prospective application. Since stock options had vested and other awards were recorded at their fair values prior to implementation of SFAS No. 123R, implementation did not have a material impact on net income or earnings per share. Pro forma net income under SFAS No. 123R for the quarter and twelve months ended Dec. 31, 2006 would not have been materially different than what was recorded.

Since the vesting of the 2004 restricted stock units is predicated on the achievement of a market condition, the achievement of a TSR, the fair value used to calculate the expense related to this award is based on the stock price on the date of grant adjusted for the uncertainty surrounding the achievement of the TSR. Since the vesting of the 2005 and 2006 restricted stock units is predicated on the achievement of a performance condition, the achievement of an earnings per share or environmental measures target, fair values used to calculate the expense on these plans are based on the amount of the award calculated as a percentage of salaries and approved by Xcel Energy’s board of directors. The performance share plan awards have been historically settled partially in cash and therefore do not qualify as an equity award, but are accounted for as a liability award. As a liability award, the fair value on which expense is based is remeasured each period based on the current stock price, and final expense is based on the market value of the shares on the date the award is settled. Compensation expense related to share-based awards of approximately $47 million and $33 million was recorded in 2006 and 2005, respectively. As of Dec. 31, 2006, there was approximately $19 million of total unrecognized compensation cost related to non-vested share-based compensation awards. Total unrecognized compensation expense will be adjusted for future changes in estimated forfeitures. We expect to recognize that cost over a weighted-average period of 1.7 years. The amount of cash used to settle these awards was $11 million and $4 million for 2006 and 2005, respectively.

F-20

Prior to 2006, Xcel Energy applied Accounting Principles Board Opinion No. 25 — “Accounting for Stock Issued to Employees” in accounting for stock-based compensation and, accordingly, no compensation cost was recognized for the issuance of stock options, as the exercise price of the options equaled the fair-market value of Xcel Energy’s common stock at the date of grant. In December 2002, the FASB issued SFAS No. 148 — “Accounting for Stock-Based Compensation — Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro forma impact of applying SFAS No. 148 was as follows at Dec. 31:

	2005				2004
	(Thousands of Dollars, except per share amounts)
Net income — as reported		$	512,972			$	355,961
Less: Total stock-based employee compensation expense determined under fair-value-based method for stock options, net of related tax effects		(1,180		)		(2,339		)
Pro forma net income		$	511,792			$	353,622
Earnings per share:
Basic — as reported		$	1.26			$	0.88
Basic — pro forma		$	1.26			$	0.87
Diluted — as reported		$	1.23			$	0.87
Diluted — pro forma		$	1.23			$	0.86

Common Stock Dividends Per Share — Historically, Xcel Energy has paid quarterly dividends to its shareholders. Dividends on common stock are paid as declared by the board of directors. Dividends paid per share for the quarters of 2006, 2005 and 2004 are:

Dividends Per Share	2006			2005			2004
First Quarter		$	0.2150		$	0.2075		$	0.1875
Second Quarter		0.2225			0.2150			0.2075
Third Quarter		0.2225			0.2150			0.2075
Fourth Quarter		0.2225			0.2150			0.2075
		$	0.8825		$	0.8525		$	0.8100

Dividend and Other Capital-Related Restrictions — The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only and not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, the capitalization ratio at Dec. 31, 2006, was 81 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $905 million in additional cash dividends on common stock at Dec. 31, 2006.

The issuance of securities by Xcel Energy generally is not subject to regulatory approval. However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC under the Federal Power Act. PSCo currently has authorization to issue up to $1.2 billion of long-term debt and $800 million of short-term debt. SPS will seek authority for long-term debt as needed. SPS currently has authorization to issue up to $250 million in short-term debt. NSP-Wisconsin currently has authorization to issue up to $125 million of long-term debt and $75 million of short-term debt. NSP-Minnesota has authorization to issue long-term securities provided the equity ratio remain between 45.99 percent and 56.21 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $5.5 billion. Xcel Energy believes these authorizations are adequate and will seek additional authorization when necessary, however, there can be no assurance that additional authorization will be granted on the timeframe or in the amounts requested.

The FERC has granted a blanket authorization for certain intra-system financings involving holding companies. In addition, Xcel Energy’s utility subsidiaries have received FERC authorization through June 30, 2008 to engage in

F-21

intra-system financings, including through the money pool, in amounts ranging from $250 million for each of NSP-Minnesota and PSCo, to $100 million for SPS and $75 million for NSP-Wisconsin.

Stockholder Protection Rights Agreement — In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.

9. Benefit Plans and Other Postretirement Benefits

Xcel Energy offers various benefit plans to its benefit employees. Approximately 56 percent of benefiting employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2006, NSP-Minnesota had 2,094 and NSP-Wisconsin had 409 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007. PSCo had 2,165 bargaining employees covered under a collective-bargaining agreement, which expires in May 2009. SPS had 733 bargaining employees covered under a collective-bargaining agreement, which expires in October 2008.

“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. Xcel Energy applied regulatory accounting treatment, which allowed recognition of this item as a regulatory asset or liability 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 or liabilities. 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
Prepaid pension asset	$	704,046			$	(117,334	)		$	—		$	586,712
Regulatory assets	736,673				—				452,472			1,189,145
Other (long-term assets)	138,519				(2,773		)		—			135,746
Prepayments and other (current deferred taxes)	202,659				3,084				—			205,743
Total Assets	$	1,781,897			$	(117,023	)		$	452,472		$	2,117,346
Other (current liabilities)	$	339,951			$	7,858			$	—		$	347,809
Pension and employee benefit obligations	$	282,380			$	422,533			$	—		704,913
Deferred income taxes	2,211,250				(211,061		)		256,410			2,256,599
Regulatory liabilities	1,577,752				—				(213,095		)	1,364,657
Total Liabilities	$	4,411,333			$	219,330			$	43,315		$	4,673,978
AOCI-net of tax	$	(89,130	)		$	(336,353	)		$	409,157		$	(16,326	)
Total Equity	$	(89,130	)		$	(336,353	)		$	409,157		$	(16,326	)

Pension Benefits

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

Xcel Energy’s 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.

F-22

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.

F-23

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

	2006				2005
	(Thousands of Dollars)
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
Settlements		—
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 Consolidated Balance Sheets		$	516,820			$	594,433
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss		$	143,695			$	281,519
Prior service cost		168,437				214,702
Total		$	312,132			$	496,221
SFAS No.158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets		$	208,216			N/A
Regulatory liabilities		89,627				N/A
Deferred income taxes		6,312				N/A
Net-of-tax AOCI		7,977				N/A
Total		$	312,132			N/A
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, one of Xcel Energy’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.

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 2003 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. In addition, Xcel Energy voluntarily contributed $2 million and $5 million to the NCE non-bargaining plan in 2006 and 2005, respectively. During 2007, Xcel Energy expects to voluntarily contribute approximately $20 million to the PSCo pension plan for bargaining employees and approximately $8 million to the NCE non-bargaining plan.

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

F-24

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:

	2006				2005				2004
	(Thousands of Dollars)
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		)
Curtailment gain		—				—				—
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 cost (credit) under SFAS No. 87		(3,976		)		(21,764		)		(65,578		)
Credits not recognized due to effects of regulation		12,637				19,368				38,967
Net benefit credit recognized for financial reporting		$	8,661			$	(2,396	)		$	(26,611	)
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. Total contributions to these plans were approximately $18.3 million in 2006, $19.6 million in 2005 and $21.9 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. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Xcel Energy discontinued contributing toward health care benefits for former NCE nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NSP who retired after 1998, bargaining employees of the former NSP who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

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

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

F-25

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. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and 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 in equity funds. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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:

	2006				2005
	(Thousands of Dollars)
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 (loss)		(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
Change in Fair Value of Plan Assets
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	)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss		$	297,745			364,745
Prior service cost (credit)		(13,558		)		(15,736		)
Transition obligation		87,633				103,022
Total		$	371,820			452,031
SFAS No. 158 Amounts Have Been Recorded as Follows Based upon Expected Recovery in Rates:
Regulatory assets		$	235,834			N/A
Regulatory liabilities		118,722				N/A
Deferred income taxes		7,004				N/A
Net-of-tax AOCI		10,260				N/A
Total		$	371,820			N/A

F-26

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 also was 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:

	(Thousands of Dollars)
1-percent increase in APBO components at Dec. 31, 2006		$	101,014
1-percent decrease in APBO components at Dec. 31, 2006		$	(84,398	)
1-percent increase in service and interest components of the net periodic cost		$	7,985
1-percent decrease in service and interest components of the net periodic cost		$	(6,533	)

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 costs are:

	2006				2005			2004
	(Thousands of Dollars)
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		)
Curtailment gain		—			—			—
Settlement gain		—			—			—
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 gain		24,797			26,246			21,651
Net periodic postretirement benefit cost under SFAS No. 106(a)		69,878			74,690			69,688
Additional cost recognized due to effects of regulation		3,891			3,891			3,891
Net cost recognized for financial reporting		$	73,769		$	78,581		$	73,579
Significant assumptions used to measure costs (income)
Discount rate		5.75		%	6.00		%	6.25		%
Expected average long-term rate of return on assets (pretax)		7.50		%	5.50-8.50		%	5.50-8.50		%

F-27

Projected Benefit Payments

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

	Projected Pension Benefit Payments			Gross Projected Postretirement Health Care Benefit Payments			Expected Medicare Part D Subsidies			Net Projected Postretirement Health Care Benefit Payments
	(Thousands of Dollars)
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

10. Detail of Interest and Other Income — Net

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

	2006				2005				2004
	(Thousands of Dollars)
Interest income		$	20,317			$	14,886			$	21,534
Equity income in unconsolidated affiliates		4,450				2,511				3,225
Other nonoperating income		5,253				8,251				11,272
Minority interest income		2,361				827				310
Interest expense on corporate-owned life insurance and other employee-related insurance policies		(27,637		)		(25,000		)		(24,601		)
Other nonoperating expense		(659		)		(618		)		(2,424		)
Total interest and other income — net		$	4,085			$	857			$	9,316

11. Derivative Instruments

In the normal course of business, Xcel Energy and its subsidiaries are 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. Xcel Energy and its subsidiaries utilize, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their 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 for generation of electricity and in the natural gas utility operations. Commodity risk also is managed through the use of financial derivative instruments. Xcel Energy’s utility subsidiaries utilize these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our 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 state regulatory cost-recovery mechanism. Xcel Energy’s risk-management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulations.

Short-Term Wholesale and Commodity Trading Risk — Xcel Energy’s utility subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and other energy-related instruments. Xcel Energy’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 — Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’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

Xcel Energy and its subsidiaries use 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

F-28

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 the utility operations 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. Xcel Energy and its subsidiaries formally document 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. Xcel Energy and its subsidiaries also formally assess, both at inception and on an ongoing 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 hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased 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 Xcel Energy and its subsidiaries are 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 — Xcel Energy’s utility subsidiaries enter 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, Xcel Energy 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, Xcel Energy had no amounts in Accumulated Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

Xcel Energy 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 — Xcel Energy and its subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.

As of Dec. 31, 2006, Xcel Energy had net gains related to interest rate swaps of approximately $1.1 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

Xcel Energy and its subsidiaries also enter 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.

F-29

As of Dec. 31, 2006, Xcel Energy had net gains related to settled interest rate lock agreements of approximately $1.4 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

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

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

	(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2003		$	8.1
After-tax net unrealized gains related to derivatives accounted for as hedges		1.6
After-tax net realized gains on derivative transactions reclassified into earnings		(9.6		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2004		$	0.1
After-tax net unrealized gains related to derivatives accounted for as hedges		4.5
After-tax net realized gains on derivative transactions reclassified into earnings		(13.4		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005		$	(8.8	)
After-tax net unrealized gains related to derivatives accounted for as hedges		11.8
After-tax net realized gains on derivative transactions reclassified into earnings		(0.8		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006		$	2.2

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Interest Rate Fair Value Hedges — Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed-rate debt. The fair market value of Xcel Energy’s interest rate swaps at Dec. 31, 2006, was a liability of approximately $8.3 million.

Normal Purchases or Normal Sales Contracts

Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.

Xcel Energy 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.

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, Xcel Energy 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, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory balances.

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

The following discussion briefly describes the use of derivative commodity and financial instruments at Xcel Energy and its subsidiaries, and discloses the respective fair values at Dec. 31, 2006 and 2005.

Commodity Trading Instruments — At Dec. 31, 2006 and 2005, the fair value of commodity trading contracts was $(1.2) million and $3.9 million, respectively.

Hedging Contracts — The fair value of qualifying cash flow hedges at Dec. 31, 2006 and 2005 was $17.6 million and $4.1 million, respectively.

F-30

Financial Instruments — Xcel Energy and its subsidiaries had interest rate swaps outstanding with a fair value that was a liability of approximately $20.9 million at Dec. 31, 2006. On Dec. 31, 2005, subsidiaries of Xcel Energy had interest rate swaps outstanding with a fair value that was a liability of approximately $44.7 million.

12. Financial Instruments

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

	2006						2005
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(Thousands of Dollars)
Nuclear decommissioning fund		$	1,200,688		$	1,200,688		$	1,047,592		$	1,047,592
Other investments		$	29,209		$	28,962		$	24,286		$	24,050
Long-term debt, including current portion		$	6,786,049		$	7,324,218		$	6,733,284		$	7,245,346

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 values of Xcel Energy’s debt securities in an external nuclear decommissioning fund and other investments are estimated based on quoted market prices for those or similar investments. The fair values of Xcel Energy’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.

The following tables provide the external decommissioning fund’s approximate gains, losses and proceeds from the sale of securities for the years ended Dec. 31:

	2006			2005			2004
	(Thousands of Dollars)
Realized gains		$	310,066		$	8,967		$	16,578
Realized losses		$	32,412		$	8,990		$	20,180
Proceeds from sale of securities		$	958,294		$	489,697		$	223,135

	2006			2005
	(Thousands of Dollars)
Unrealized gains		$	41,355		$	253,991
Unrealized losses		$	—		$	10,558

Xcel Energy provides guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantee. Unless otherwise indicated below, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral.

F-31

On Dec. 31, 2006, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to Seren, UE, Quixx and Xcel Energy Argentina, which are components of discontinued operations:

Nature of Guarantee

Guarantor

Guarantee
Amount

Current
Exposure

Term or
Expiration Date

Triggering
Event
Requiring
Performance

Assets
Held as
Collateral

(Millions of Dollars)

Guarantee performance and payment of surety bonds for itself and its subsidiaries(f)

Xcel Energy

118.6

(a)

2007- 2009, 2012, 2014, 2015 and 2022

(d)

N/A

Guarantee the indemnification obligations of Xcel Energy Wholesale Group Inc. under a stock purchase agreement

Xcel Energy

17.5

(g)

2010

(c)

N/A

Guarantee the indemnification obligations of Xcel Energy Argentina under a stock purchase agreement

Xcel Energy

14.7

—

Continuing

(c)

N/A

Guarantee the indemnification obligations of Seren under an asset purchase agreement

Xcel Energy

12.5

—

Continuing

(c)

N/A

Guarantee the indemnification obligations of Seren under an asset purchase agreement

Xcel Energy

20.0

—

Continuing

(c)

N/A

Guarantee of customer loans for the Farm Rewiring Program

NSP-Wisconsin

1.0

—

Continuing

(e)

N/A

Combination of guarantees benefiting various Xcel Energy subsidiaries

Xcel Energy

10.5

—

Continuing

(b)(c)

N/A

(a)		The total exposure of this indemnification cannot be determined. Xcel Energy believes the exposure to be significantly less than the total amount of the outstanding bonds.
(b)		Nonperformance and/or nonpayment.
(c)		Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement.
(d)		Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
(e)		The debtor becomes the subject of bankruptcy or other insolvency proceedings.
(f)		Xcel Energy agreed to indemnify an insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up to $80 million. The Xcel Energy indemnification will be triggered only in the event that Utility Engineering has failed to meet its obligations to the surety company.
(g)		See Note 14 to the Consolidated Financial Statements for further discussion of Fru-Con Construction Corporation vs. Utility Engineering et al.

F-32

Letters of Credit

Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2006, there was $43.8 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

13. Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — FERC

MISO Operations — NSP-Minnesota and NSP-Wisconsin are members of the MISO. The MISO is a FERC-regulated RTO that provides regional transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin. MISO also operates a regional wholesale energy market using Locational Marginal Pricing and financial congestion relief which is also known as a Day 2 market. NSP-Minnesota recovers most MISO regional market charges through the FCA. NSP-Wisconsin currently has requested recovery of these costs within its jurisdiction. For further discussion, see Pending and Recently Concluded Regulatory Proceedings — MPUC and Pending and Recently Concluded Regulatory Proceedings — PSCW.

Within MISO, an independent market monitor (IMM) reviews market bids and prices to identify any unusual activity. Xcel Energy and other market participants continue to work with MISO, the IMM and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details.

MISO Long-Term Transmission Pricing — In October 2005, MISO filed a proposed change to its TEMT to regionalize future cost recovery of certain high voltage (345 KV) transmission projects to be constructed for reliability improvements. The proposal, called the Regional Expansion Criteria Benefits phase 1 (RECB I) proposal, would recover 20 percent of eligible transmission costs from all transmission service customers in the MISO 15 state region, with 80 percent recovered on a sub-regional basis. The proposal would exclude certain projects that had been planned prior to the October 2005 filing, and would require new generators to fund 50 percent of the cost of network upgrades associated with their interconnection. In February 2006, the FERC generally approved the RECB I proposal, but set the 20 percent limitation on regionalization for additional proceedings. Various parties filed requests for rehearing. On Nov. 29, 2006, the FERC issued an order on rehearing upholding the February 2006 order and approving the 20 percent limitation. On Dec. 13, 2006, the PSCW filed an appeal of the RECB I order.

In addition, in October 2006, MISO filed additional changes to its TEMT to regionalize future recovery of certain transmission projects (230 KV and above) constructed for “economic” reasons (e.g., to provide access to lower cost generation supplies). The filing, known as RECB II, would provide regional recovery of 20 percent of the project costs and sub-regional recovery of 80 percent, based on a benefits analysis. MISO proposed that the RECB II tariff be effective April 1, 2007. Initial comments were filed at FERC on Dec. 22, 2006. The date FERC will take initial action is not known.

Transmission service rates in the MISO region presently use a rate design, in which the transmission cost depends on the location of the load being served. Costs of existing transmission facilities are not regionalized. MISO is required to file a replacement rate methodology in August 2007, to be effective Feb. 1, 2008. It is possible MISO will propose to regionalize the recovery of the costs of existing transmission facilities. Proposals to regionalize transmission costs could shift the costs of NSP-Minnesota and NSP-Wisconsin transmission investments to other MISO transmission service customers, but would also shift the costs of transmission investments in other parts of MISO to NSP-Minnesota and NSP-Wisconsin.

MISO/PJM SECA — On Nov. 18, 2004, the FERC issued an order approving portions of a plan providing for continued use of location based rates for the MISO/PJM region, but rejecting proposed transition payments to compensate transmission owners for reductions in transmission revenues. The FERC instead ordered the MISO and PJM to each file a Seams Elimination Charge Adjustment (SECA) transition mechanism. The replacement compliance filings were effective Dec. 1, 2004, subject to refund.

The competing SECA compliance proposals were the subject of litigated hearings at the FERC. Certain parties proposed a regional average SECA charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin. On Aug. 10, 2006, the ALJ in the case issued an initial decision recommending that all the SECA compliance filings be rejected and recommending adoption of a regional SECA, which could shift approximately $13 million in charges to NSP-Minnesota and NSP-Wisconsin. Xcel Energy, through the MISO transmission owners, filed exceptions to the ALJ initial decision, arguing the decision directly violates the 2004 FERC orders. In addition, the MISO transmission owners have executed settlements

F-33

with several parties in the litigation. The settlement resolves specific claims and would limit any regionalization to unresolved claims. Final FERC action is expected in the SECA litigation in 2007.

Revenue Sufficiency Guarantee Charges — On April 25, 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from certain MISO customers and paid to others. Based on the FERC order, NSP-Minnesota could be required to make net payments to MISO. On Oct. 26, 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to implement prospective changes. In late November 2006, however, certain parties filed further requests for rehearing challenging the reversal regarding refunds. The date of a final FERC decision is unknown, and one appeal has been filed. Xcel Energy reserved $6.1 million in response to the April 25, 2006, FERC order.

Pending and Recently Concluded Regulatory Proceedings — MPUC

NSP-Minnesota Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.

On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized return on equity of 10.54 percent. The scheduled rate increase will be reduced in 2007 to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system. The MPUC approved the wholesale margin settlement in which NSP-Minnesota returns most margins from unused generating capacity back to customers through the FCA mechanism. NSP-Minnesota is allowed to earn an incentive on sales related to ancillary service obligations. The MPUC Order became effective in November 2006, and final rates were implemented on February 1, 2007. A citizen intervenor has appealed the MPUC’s decision.

NSP-Minnesota Natural Gas Rate Case — On Nov. 9, 2006, NSP-Minnesota filed a request with MPUC to increase Minnesota natural gas rates by $18.5 million annually, which represents an increase of 2.4 percent. The request was based on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million annual increase and went into effect on Jan. 8, 2007. A final decision is expected in the third quarter of 2007.

North Dakota Gas Rate Case — On Dec. 15, 2006, NSP-Minnesota filed a notice of rate change with the NDPSC requesting an increase of natural gas distribution rates of $2.8 million annually, or 3 percent. In February 2007, the NDPSC approved interim rates of $2.2 million. Interim rates would remain in effect until the NDPSC makes its final determination in the summer of 2007. Final natural gas rates will be put into place after the decision.

Renewable Transmission Cost Recovery — Since December 2004, NSP-Minnesota has recovered certain transmission costs related to wind generation projects through a RCR rider. In November 2006, the MPUC approved the replacement of the RCR rider with a TCR rider pursuant to 2005 legislation. The TCR mechanism would allow recovery of incremental transmission investments between rate cases. On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.8 million in 2007 revenue requirements under the TCR tariff. Final MPUC action is expected later in the first quarter of 2007. The RCR rate factors will remain in effect until the TCR factors are implemented.

MISO Day 2 Market Cost Recovery — On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its FCA. A Dec. 21, 2006 MPUC order ruled that all MISO costs, except Schedule 16 and 17, can be recovered through the FCA. Schedules 16 and 17 costs were recovered through the FCA in 2005. However, the MPUC’s Dec. 21, 2006 order requires NSP-Minnesota to refund these costs to customers through the FCA in equal monthly installments beginning March 2007. It also provided the opportunity to defer 100 percent of the 2005 costs for a three-year period before starting the amortization. A refund liability was recorded for $4.4 million.

In March 2005, NSP-Minnesota filed petitions similar to the December 2004 Minnesota filing with the NDPSC and the SDPUC proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs. The SDPUC approved the proposed tariff changes, effective April 1, 2005, as requested. The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but conditioned the relief as being

F-34

subject to refund until the merits of the case are determined. Since April 1, 2005, NSP-Minnesota has collected approximately $28 million of MISO Day 2 charges through its North Dakota FCA.

NSP-Wisconsin

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Case Application — On July 31, 2006, NSP-Wisconsin filed a rate case at the FERC requesting a base rate increase of approximately $4 million, or 15 percent, for its ten wholesale municipal electric sales customers. NSP-Wisconsin’s wholesale customers are currently served under a bundled full requirements tariff, with rates based on embedded costs, and a monthly fuel cost adjustment clause (FCAC). NSP-Wisconsin proposes to unbundle transmission service and revise the FCAC to reflect current FERC regulatory policies, the advent of MISO operations and the MISO Day 2 energy market. In August 2006, ten customers filed a joint protest of the rate case, requesting the increase be suspended until March 1, 2007 and the request be set for litigated hearings. On Sept. 28, 2006, the FERC issued an order accepting the filing, suspending the effective date of the rates to March 1, 2007, and setting the filing for hearing and settlement judge procedures. In February 2007, NSP-Wisconsin reached a settlement with customers that provides for full cost recovery of MISO Day 2 and renewable energy costs through the FCA and a $2.4 million base rate increase.

Pending and Recently Concluded Regulatory Proceedings — PSCW

MISO Cost Recovery — On March 29, 2005, NSP-Wisconsin received an order from the PSCW granting its request to defer the costs and benefits attributable to the start-up of the MISO Day 2 energy market.

On June 16, 2006, the PSCW issued its written order regarding the joint request for escrow accounting treatment of MISO Day 2 costs made by NSP-Wisconsin and other Wisconsin utilities. The order confirms continued deferred accounting treatment for congestion costs, net line losses, and costs of acquiring FTRs not received in the MISO allocation process, as previously authorized by the PSCW. The order also clarifies that deferral is authorized for several additional MISO Day 2 cost and revenue types not explicitly addressed in the original PSCW order issued March 29, 2005.

On June 29, 2006, the PSCW opened a proceeding to address the proper amount of MISO Day 2 deferrals that the state’s utilities should be allowed to recover and the proper method of rate recovery.

On Sept. 1, 2006, NSP-Wisconsin detailed its calculation methodology and reported that, as of June 30, 2006, it had deferred approximately $6.2 million. PSCW staff and intervenors filed testimony in December 2006, arguing that the various methodologies used by the utilities to calculate the deferrals were inconsistent, and to varying degrees incorrect. Further, the testimony argued that some or all of the deferred costs are being recovered in current rates and were, therefore, inappropriately deferred and the utilities should be required to write off balances that were inappropriately deferred. The potential impact of PSCW Staff recommendations on NSP-Wisconsin is unknown at this time but could be material. NSP-Wisconsin currently anticipates that the ultimate decision on the amount of costs to be recovered in rates could be delayed until its next general rate case to be filed on June 1, 2007.

As of Dec. 31, 2006 NSP-Wisconsin has deferred a total of approximately $11.2 million of MISO Day 2 costs.

2006 General Rate Case — In 2005, NSP-Wisconsin, requested an electric revenue increase of $58.3 million and a natural gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent. On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on an 11.0 percent return on equity and a 54-percent common equity ratio target. The new rates were effective Jan. 9, 2006. The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average common equity ratio is or will fall below 54.03 percent. It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates.

2006 Fuel Cost Recovery — Fuel costs for the Wisconsin retail jurisdiction in 2006 were $14.4 million, or 9.7 percent lower than the fuel-related component of base electric rates authorized in the 2006 general rate case. Under the provisions of the Wisconsin Fuel Rules and a May 4, 2006 order from the PSCW, NSP-Wisconsin is required to refund, with interest, that portion of the over-recovery that occurred subsequent to the May 4 order. Accordingly, NSP-Wisconsin established a $10.1 million fuel refund provision during 2006. On Jan. 30, 2007, NSP-Wisconsin filed its 2006 year-end fuel cost recovery report and a proposed refund plan with the PSCW. On Feb. 8, 2007, the PSCW approved the refund and NSP-Wisconsin began crediting customers Feb. 15, 2007.

F-35

2007 Fuel Cost Recovery — On Aug. 4, 2006, NSP-Wisconsin filed an application to reset the 2007 fuel base and monitoring range, and to increase electric base rates for 2007 by $22.7 million, or 5.0 percent, on an annual basis. The requested increase was driven primarily by higher renewable energy purchases and increases in coal commodity and transportation costs. On Dec. 22, 2006 the PSCW issued an order approving an electric rate increase of $13.8 million, reflecting decreases in natural gas and purchased power costs on an annual basis, and authorized the return to a symmetrical fuel clause bandwidth of plus or minus 2 percent. New rates became effective Jan. 1, 2007.

Fuel Cost Recovery Rulemaking — On June 22, 2006, the PSCW opened a rulemaking docket to address potential revisions to the electric fuel cost recovery rules. Wisconsin statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities. Instead, the statutes authorize the PSCW to approve, after a hearing, a rate increase for these utilities to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel. In opening this rulemaking, the PSCW recognized the increased volatility of fuel costs, citing events such as the implementation of the MISO Day 2 Market, increased demand on some fuels, increased transportation costs of some fuels, and the effects of hurricanes on the availability of some fuels. On Sept. 7, 2006, Wisconsin’s large investor-owned utilities, including NSP-Wisconsin, jointly filed proposed revisions to the rules. The utilities’ proposal incorporates a plan year forecast and an after-the-fact reconciliation to eliminate regulatory lag, and ensure recovery of prudently incurred costs. On Nov. 3, 2006, a coalition of customer and intervenor groups submitted a counter proposal that included only minor revisions to the existing rules. At this time it is not certain what, if any, changes to the existing rules will be recommended by the PSCW.

PSCo

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.

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 that would increase annual revenues by $41.5 million, 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.

SPS

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, wholesale cooperative customers of SPS, filed a rate

F-36

complaint at the FERC. The complaint alleged that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustments using the FCAC provisions contained in SPS’ wholesale rate schedules. Among other things, the complainants asserted that SPS was not properly calculating the fuel costs that are eligible for FCAC recovery to reflect fuel costs recovered from certain wholesale sales to other utilities, and that SPS had inappropriately allocated average fuel and purchased power costs to other of SPS’ wholesale customers, effectively raising the fuel costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental) intervened in the proceeding.

On May 24, 2006, a FERC ALJ issued an initial recommended decision in the proceeding. The FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s initial recommendation. FERC’s order may or may not follow any of the ALJ’s recommendation. In the recommended decision, the ALJ found that SPS should recalculate its FCAC billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm capacity and associated energy to other firm customers at market-based rates during this period based on the view that such sales should be treated as opportunity sales.

SPS believes the ALJ erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of customers. These market-based sales were of a long-term duration under FERC precedent and were made from SPS’ entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales, which require the assignment of incremental costs.

The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing.

Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the Filed Rate Doctrine in that it effectively results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing regulations, the FERC may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.

SPS has evaluated all sales made from Jan. 1, 1999, to Dec. 31, 2005. While SPS believes it should ultimately prevail in this proceeding, SPS has accrued approximately $7 million, related to both the base-rate and fuel items. However, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million. FERC action is pending.

On Sept. 15, 2005, PNM filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous FCAC calculations. PNM’s arguments were consistent with those that it made as an intervenor in the cooperatives’ complaint case. In July 2006, SPS and PNM reached a settlement in principle and a settlement agreement was filed for approval on Sept. 19, 2006. As a consequence, SPS has accrued approximately $1.3 million to settle all related base rate issues for this complaint. Several intervenors have protested the settlement. The settlement is pending.

Wholesale Power Base Rate Application — On Dec. 1, 2005, SPS filed for a $2.5 million increase in wholesale power rates to certain electric cooperatives. On Jan. 31, 2006, the FERC conditionally accepted the proposed rates for filing, and the $2.5 million power rate increase became effective on July 1, 2006, subject to refund. The FERC also set the rate increase request for hearing and settlement judge procedures. The case is presently in the settlement judge procedures and an agreement in principle has been reached for base rates for the full-requirements customers and PNM. One other wholesale customer has not settled, however. On Sept. 7, 2006, the offer of settlement with respect to the full-requirements customer was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed for approval. Hearings have been scheduled for April 2007 for the base rates applicable to the remaining non-settling wholesale customer.

SPP Energy Imbalance Service — On June 15, 2005, SPP, the RTO for the SPS system, filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region. This market is the first step in a phased approach toward the development of a more comprehensive regional energy market, which is expected to eventually include an ancillary services component and perhaps financial congestion costs known as FTRs. SPP implemented the EIS

F-37

market Feb. 1, 2007. Xcel Energy and other market participants are working with the SPP to resolve implementation issues related to the new market.

Pending and Recently Concluded Regulatory Proceedings — PUCT

Fuel Cost Recovery Mechanisms — Fuel and purchased energy costs are recovered in Texas through a fixed-fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. The Texas retail fuel factors change each November and May based on the projected cost of natural gas. If it appears SPS will materially over-recover or under-recover these costs, the factor may be revised based on application by SPS or action by the PUCT.

Texas Retail Fuel Surcharge Case — On May 5, 2006, SPS requested authority to surcharge approximately $45.5 million of Texas retail fuel and purchased energy cost under-collection that accrued from October 2005 through March 2006. The case was referred to the State Office of Administrative Hearing (SOAH) for a contested hearing. During the course of this proceeding, certain customers challenged whether a wholesale firm sales contract that SPS has with El Paso Electric Company (EPE) satisfied the terms of a non-unanimous stipulation, dated April 25, 2005, and the PUCT’s final order, dated Dec. 19, 2005. This order established the terms under which SPS would be allowed to recover system average fuel cost from certain wholesale firm sales contracts until the issue is addressed in SPS’ base rate case. In October 2006, the PUCT announced its decision that the contract with EPE, which was entered into in July 2004 did not conform to the non-unanimous stipulation and the PUCT’s December 2005 final order. As a result, the PUCT disallowed approximately $1.8 million in fuel costs for the period covering October 2005 through March 2006. The PUCT rejected two requests for rehearing on the EPE contract. SPS has accrued $8.1 million as of Dec. 31, 2006. The order will remain in effect until the end of SPS’ general rate case proceeding at which time the terms of the non-unanimous settlement on the treatment of wholesale sales are set to expire. Recovery of the remaining portion of the surcharge of approximately $39 million began on Oct. 1, 2006.

Texas Retail Fuel Factor Change — On Oct. 6, 2006, SPS filed an application to change its fuel factors effective Nov. 1, 2006, to more accurately track fuel cost during the winter months. On Oct. 16, 2006, the PUCT granted interim approval of the factor changes effective Nov. 2006. On Nov. 30, 2006, the PUCT granted final approval.

Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million, or 6.0 percent. The rate filing is based on a historical test year, an electric rate base of $943 million, a requested return on equity of 11.6 percent and a common equity ratio of 51.1 percent.

In addition, SPS has a pending fuel reconciliation filing, which seeks approval of approximately $957 million of Texas jurisdictional fuel and purchased power costs for 2004 through 2005. The fuel reconciliation case was transferred to the SOAH with the base rate case and has the same procedural schedule. As a part of the fuel reconciliation case, fuel and purchased energy costs, which are recovered in Texas through a fixed-fuel and purchased energy recovery factor as a part of SPS’ retail electric rates, will be reviewed.

Various parties have filed testimony on base rate and fuel issues, including the Office of Public Utility Counsel; the state of Texas; Texas Industrial Energy Consumers; Alliance of Xcel Municipalities; Occidental Permian; and the PUCT staff. Intervenors recommendations ranged from a base rate reduction of $56 million to a base rate increase of $31 million.

In the fuel reconciliation portion of the proceeding, the parties recommended several adjustments related to SPS’s fuel reconciliation filing, including the methodology for assigning average fuel costs to certain firm wholesale sales, coal mitigation activities, the treatment of fuel losses and other items. The recommendation for disallowances ranged from $8 million to a disallowance of $120 million. In addition, the Alliance of Xcel Municipalities challenged the prudence of the decision to enter into certain coal contracts in 2005 and 2006. The proposed disallowances over the life of two contracts through 2010 and 2017, respectively, is in excess of $100 million.

SPS’ rebuttal testimony was filed in January 2007. SPS is confident that the rebuttal case adequately addressed many of the concerns raised by intervenors. As of Dec. 31, 2006 SPS has recognized what it believes is an appropriate level of reserves for this potential liability.

Pending and Recently Concluded Regulatory Proceedings — NMPRC

New Mexico Fuel Review — On Jan. 28, 2005, the NMPRC accepted the staff petition for a review of SPS’ fuel and purchased power cost. The staff requested a formal review of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004. The hearing in the fuel review case was held April 22,

F-38

2006. A proposed recommended decision was filed by the parties on July 28, 2006, and the hearing examiner’s recommendation and a NMPRC decision are expected in early 2007.

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ FPPCAC and current monthly factor cost recovery methodology. This filing was required by NMPRC rule. Testimony has been filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of ineligible purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues some intervenors have requested disallowances for past periods, which in the aggregate total approximately $45 million. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause. The hearing was held in April 2006, and the hearing examiner’s recommended decision and a NMPRC decision is expected in early 2007.

14. Commitments and Contingent Liabilities

Commitments

Capital Commitments — The estimated cost as of Dec. 31, 2006 of capital requirements of Xcel Energy and its subsidiaries and the capital expenditure programs is approximately $1.9 billion in 2007, $1.9 billion in 2008 and $1.7 billion in 2009. Xcel Energy’s capital forecast includes the following major projects:

CAPX 2020 — In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified three groups of transmission projects that proposed to be complete by 2020. Group 1 project investments are expected to total approximately $1.3 billion, with major construction targeted to begin in 2009 or 2010 and ending three or four years later. Xcel Energy’s investment is expected to be approximately $700 million. Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota transmission cost recovery tariff rider mechanism authorized by Minnesota legislation and pending MPUC approval. Similar transmission cost recovery mechanisms have been proposed in North Dakota and South Dakota. Cost recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.

Nuclear Capacity Increases and Life Extension — In August 2004, NSP-Minnesota announced plans to pursue 20-year license renewals for the Monticello and Prairie Island nuclear plants, whose licenses will expire between 2010 and 2014. License renewal applications for Monticello were submitted to the NRC and the MPUC in early 2005. License renewal was approved by the NRC in November 2006, and the MPUC issued its approval in October 2006 allowing additional spent fuel storage. The MPUC stayed the order until June 2007, following the Minnesota legislative session. Similar applications will be submitted for Prairie Island in 2008, with approval expected in 2010.

At the direction of the MPUC, NSP-Minnesota is pursuing capacity increases of all three units that will total approximately 250 MW, to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned for replacement during the refueling outage in 2013. Total capital investment for these activities is estimated to be approximately $1 billion between 2006 and 2015. NSP-Minnesota plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs. It is NSP-Minnesota’s plan to submit the certificate of need for Monticello in the second quarter of 2007 and the certificate of need for Prairie Island in the third quarter of 2007.

MERP Project — In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. Major construction for the MERP project began in 2005, and these projects are expected to come on line between 2007 and 2009. The cumulative investment is approximately $1 billion. The MPUC has approved a more current recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider, which was effective Jan. 1, 2006.

Comanche 3 — Comanche 3, a 750 MW coal-fired plantbeing 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.

F-39

Sherco Project — NSP-Minnesota has proposed a $905 million upgrade at the Sherburne County (Sherco) coal-fired power plant. The project will increase capacity and reduce emissions. The MPUC is expected to rule on the project in 2008. If approved, construction would start in late 2008 and be completed in 2012.

Wind Generation — NSP-Minnesota plans to invest $205 million to acquire 100-MW of wind generation. The project would be eligible for rider recovery in Minnesota. The project requires approval by the MPUC.

The capital expenditure programs of Xcel Energy 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 Xcel Energy’s long-term energy needs. In addition, Xcel Energy’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.

Leases — Xcel Energy and its subsidiaries lease 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:

	2006				2005
	(Millions of Dollars)
Storage, leaseholds and rights		$	40.5			$	40.5
Gas pipeline		20.7				20.7
		61.2				61.2
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 for Xcel Energy and its subsidiaries was approximately $60.3 million, $57.2 million and $57.5 million for 2006, 2005 and 2004, respectively.

Future commitments under operating and capital leases for continuing operations are:

	Operating Leases			Capital Leases
	(Millions of Dollars)
2007		$	57.4		$	6.3
2008		$	53.2		6.1
2009		$	53.5		6.0
2010		$	51.9		5.8
2011		$	49.5		5.6
Thereafter		$	546.3		62.4
Total minimum obligation					$	92.2
Interest component of obligation					(46.0		)
Present value of minimum obligation					$	46.2

Technology Agreement — Xcel Energy has a contract that extends through 2015 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. In 2006, Xcel Energy paid IBM $129.2 million under the contract and $0.6 million for other project business. The contract also has a committed minimum payment each year from 2007 through September 2015.

F-40

Fuel Contracts — Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2007 and 2027. In total, Xcel Energy is committed to the minimum purchase of approximately $3.4 billion of coal, $386.6 million of nuclear fuel and $2.5 billion of natural gas, including $1.5 billion of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

Purchased Power Agreements — The utility subsidiaries of Xcel Energy have 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. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indices. However, the effects of price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2006, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:

	(Millions of Dollars)
2007		$	552.9
2008		591.2
2009		626.2
2010		614.6
2011		606.6
2012 and thereafter		4,240.4
Total		$	7,231.9

Environmental Contingencies

Xcel Energy and its subsidiaries have been, or are currently involved with, the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved 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 Xcel Energy and its subsidiaries, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense.

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

· Sites of former MGPs operated by Xcel Energy subsidiaries or predecessors; and

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

Xcel Energy 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 when 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 $30.8 million, of which $5.3 million was considered to be a current liability. Some of the cost of remediation may be recovered from:

· Insurance coverage;

F-41

· 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 Xcel Energy’s future costs for these sites.

Manufactured Gas Plant Sites

Ashland Manufactured Gas Plant Site — NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon Bay adjoining the park.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). A determination of the scope and cost of the remediation of the Ashland site is not currently expected until late 2007 or 2008 following the submission of the remedial investigation report and feasibility study in 2007. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site. In November 2005, the EPA Superfund Innovative Technology Evaluation Program (SITE) accepted the Ashland site into its program. As part of the SITE program, NSP-Wisconsin proposed to perform a site demonstration of an in situ, chemical oxidation technique to treat upland ground water and contaminated soil. During the third quarter of 2006, the proposal was favorably reviewed by EPA, and in November 2006 the demonstration study was initiated. In 2006, NSP-Wisconsin spent $2.0 million in the development of the work plan, the interim response action and other matters related to the site.

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable. NSP-Wisconsin has recorded a liability of $25.0 million for its potential liability for remediating the Ashland site and for external legal and consultant costs. Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, that portion of the recorded liability related to remediation is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods.

On Oct. 19, 2004, the WDNR filed a lawsuit in Wisconsin state court for reimbursement of past oversight costs incurred at the Ashland site between 1994 and March 2003 in the approximate amount of $1.4 million. The lawsuit has been stayed. NSP-Wisconsin has recorded an estimate of its potential liability. All costs paid to the WDNR are expected to be recoverable in rates.

In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may also have liability for natural resource damages (NRDA) at the Ashland site. NSP-Wisconsin has indicated to the relevant natural resource trustees its interest in engaging in discussions concerning the assessment of natural resources injuries and in proposing various restoration projects in an effort to fully and finally resolve all NRDA claims. NSP-Wisconsin is not able to estimate its potential exposure for natural resource damages at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based upon an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for MGP-related environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers.

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

F-42

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 our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations in Note 14. 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.

Cunningham Station Groundwater — Cunningham Station is a natural gas-fired power plant constructed in the 1960s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. SPS is evaluating implementation of a similar project at Maddox Station. These actions for Cunningham and Maddox are estimated to cost approximately $4.2 million through 2008 and will be capitalized or expensed as incurred.

Construction and liner installation of the new pond has been completed. A permit application for discharges from the pond has been submitted to the NMED. It is expected that the pond will be ready to be placed into service when the NMED issues Cunningham a permit. The permitting process for Maddox has begun.

Other Environmental Requirements

CAIR — In March 2005, the EPA issued the CAIR to further regulate SO2 and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis

F-43

for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration. Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not contribute significantly to nonattainment with the fine particulate matter National Ambient Air Quality Standard in any downwind jurisdiction.

On March 15, 2006, the EPA denied the petition for reconsideration. On June 27, 2006, Xcel Energy and the other parties filed a petition for review of the denial of the petition for reconsideration, as well as a petition for review of the Federal Implementation Plan, with the United States Court of Appeals for the District of Columbia Circuit. Pursuant to the court’s scheduling order, briefing is expected to be finalized in September 2007.

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, Xcel Energy currently believes that with the installation of low NOx burners on Harrington 3 in 2006, there are capital investments estimated at $23 million remaining for NOx controls in the SPS region. Annual purchases of SO2 allowances are estimated in the range of $12 million to $26 million each year, beginning in 2012, for phase I, based on allowance costs and fuel quality as of December 2006.

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted. Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to $40 million. Xcel Energy is not challenging CAIR in these states.

These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditures and operating expenses.

While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

CAMR — In March 2005, the EPA issued the CAMR, which regulates mercury emissions from power plants for the first time. The EPA’s CAMR uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 MW. Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Xcel Energy continues to evaluate the strategy for complying with CAMR. NSP-Minnesota currently estimates the capital cost for compliance to be $10.3 million for mercury control and continuous monitoring equipment and increased operating and maintenance expenses of approximately $4.8 million. Recent testing indicates that NSP-Wisconsin facilities will be low mass mercury emitters: therefore, compliance with CAMR is not expected to require mercury controls or purchases of allowances. 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 CAPCD. The rule requires controls to be installed at Pawnee Station in 2012 and all other Colorado units by 2014. Xcel Energy is evaluating the emission controls required to meet the new rule and is currently unable to provide a capital cost estimate. SPS continues to evaluate the strategy for complying with CAMR and estimates capital costs of $14.5 million for mercury control equipment.

Minnesota Mercury Legislation — On May 2, 2006 the Minnesota Legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury

F-44

emissions at certain power plants. For Xcel Energy, the Act covers units at the A. S. King and Sherco generating facilities. Under the Act, Xcel Energy must install, maintain and operate continuous mercury emission monitoring systems or other monitoring methods approved by the MPCA at these units by July 1, 2007. The information obtained will be used to establish a baseline from which to measure mercury emission reductions. Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007 (dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce emissions by 90 percent. Implementation would occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec.31, 2010 for the remaining dry scrubbed unit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is currently estimated at $10.3 million for the mercury control and continuous monitoring equipment and increased operating and maintenance expenses of approximately $11.3 million, beginning in 2010. Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for deferred accounting of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act. On Jan. 11 2007, the MPUC approved this request for deferred accounting with a cap of $6.3 million.

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 BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements.

The EPA required states to develop implementation plans to comply with BART by December 2007. States are required to identify the facilities that will have to reduce 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 CAPCD. 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. Xcel Energy expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2008 and 2012.

Minnesota has also begun implementing its BART strategy as the first step toward the December 2007 deadline. NSP-Minnesota submitted its BART alternatives analysis for Sherco units 1 and 2 on Oct. 26, 2006. The expected cost associated with the range of alternatives for additional emission controls for SO2 and NOx is a capital investment of $7 million to $617 million. NSP- Minnesota supports the alternative with the associated cost estimate of $7 million; however, NSP-Minnesota has not yet received a response from the MPCA concerning its preferred alternative. Xcel Energy expects that the costs of any required capital investment will be recoverable from customers. All BART issues are addressed by the voluntary capacity upgrades noted below.

Voluntary Capacity Upgrade and Emissions Reduction Filing — On Jan. 2, 2007, NSP-Minnesota made a filing to the MPUC for a major emissions reduction project at the Sherco Units 1, 2 and 3 to reduce emissions and expand capacity by installing NOx controls (low NOx burners, overfire air and Selective Catalytic Reduction), installing mercury control systems, replacing the wet scrubbers on units 1 and 2 with semi-dry scrubbers, retrofitting different sections of the turbines on all three units, replacing generators and other associated equipment on all three units, and installing additional cooling capacity. The projected cost of this project is approximately $905 million and encompasses the BART capital investment of $7 million to $617 million noted above. NSP-Minnesota’s investments are subject to the MPUC approval of a cost recovery mechanism.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the “best technology available” 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 the EPA will stay the deadlines in the rule until the remanded rulemaking

F-45

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.

PSCo 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 Xcel Energy in September 2002 to discuss the NOV.

Asset Retirement Obligations

Xcel Energy 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 ARO — Asset retirement obligations have been recorded for plant related to nuclear production, steam production, electric transmission and distribution, natural gas transmission and distribution and office buildings. The steam production obligation includes asbestos, ash-containment facilities and decommissioning. The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. Generally, this asbestos abatement removal obligation originated in 1973 with the CAA, 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 NSP-Minnesota, PSCo and SPS 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.

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

For the nuclear assets, the ARO associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility. Monticello began operation in 1971. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively. See Note 15 to the Consolidated Financial Statements for further discussion of nuclear obligations.

F-46

If Xcel Energy had implemented FIN No. 47 at Jan. 1, 2005, the liability for asset retirement obligations would have increased by $55.2 million.

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

	Beginning Balance Jan. 1, 2006		Liabilities Recognized			Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2006
	(Thousands of Dollars)
Electric Utility Plant:
Steam production asbestos	$	34,323		$	—	$	—		$	1,971	$	(779	)	$	35,515
Steam production ash containment	20,934			—		—			1,183		(701		)	21,416
Steam production retirement	3,152			—		(3,309		)	157		—			—
Nuclear production decommissioning	1,184,968			—		—			71,795		—			1,256,763
Electric transmission and distribution	2,350			—		—			62		(418		)	1,994
Gas Utility Plant:
Gas transmission and distribution	43,245			15		—			1,074		71			44,405
Common Utility and Other Property:
Common general plant asbestos	3,034			—		—			162		(1,338		)	1,858
Total liability	$	1,292,006		$	15	$	(3,309	)	$	76,404	$	(3,165	)	$	1,361,951

	Beginning Balance Jan. 1, 2005		Liabilities Recognized			Liabilities Settled			Accretion		Revisions to Prior Estimates		Ending Balance Dec. 31, 2005
	(Thousands of Dollars)
Electric Utility Plant:
Steam production asbestos	$	—		$	5,917		$	—	$	28,406	$	—	$	34,323
Steam production ash containment	—			4,916			—		16,018		—		20,934
Steam production retirement	3,002			—			—		150		—		3,152
Nuclear production decommissioning	1,088,087			—			—		70,736		26,145		1,184,968
Electric transmission and distribution	—			2,350			—		—		—		2,350
Gas Utility Plant:
Gas transmission and distribution	—			43,245			—		—		—		43,245
Common Utility and Other Property:
Common general plant asbestos	—			575			—		2,459		—		3,034
Total liability	$	1,091,089		$	57,003		$	—	$	117,769	$	26,145	$	1,292,006

The fair value of NSP-Minnesota assets legally restricted, for purposes of settling the nuclear asset retirement obligation is $1.2 billion as of Dec. 31, 2006, including external nuclear decommissioning investment funds and internally funded amounts.

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 — Xcel Energy accrues an obligation for plant removal costs for other generation, transmission and distribution facilities of its utility subsidiaries. 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, the utility subsidiaries have 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 by entity are as follows at Dec. 31:

	2006			2005
	(Millions of Dollars)
NSP-Minnesota		$	355		$	334
NSP-Wisconsin		91			86
PSCo		389			377
SPS		85			98
Total Xcel Energy		$	920		$	895

F-47

Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $15 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $26.1 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

In the normal course of business, Xcel Energy is subject to claims and litigation arising from prior and current operations. Xcel Energy is actively defending these matters and has recorded a reasonable liability related to the probable cost of settlement or other disposition when it can be reasonably estimated. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

Bender et al. vs. Xcel Energy — On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the ERISA by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment. On July 26, 2005, the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference with ERISA benefits, breach of contract for nonpayment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part with respect to the allegations of nonpayment of deferred compensation benefits. Plaintiffs and Xcel Energy filed additional cross motions for summary judgment, with oral arguments presented on Feb. 24, 2006.

On May 17, 2006, the court granted Xcel Energy’s motion for summary judgment in full and denied the plaintiff’s motion for summary judgment in full. Plaintiffs have appealed to the Eighth Circuit Court of Appeals. Oral arguments were presented Jan. 11, 2007.

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

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. — On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming

F-48

e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred by the Multi-District Litigation (MDL) Panel to U.S. District Judge Pro, in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On May 9, 2005, plaintiffs filed an appeal of this decision to the 9th Circuit Court of Appeals and oral arguments on the appeal were heard on Feb. 13, 2007.

Fairhaven Power Company vs. Encana Corporation et al. — On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. The plaintiffs subsequently appealed and the appeal is pending.

Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. — On Nov. 29, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed and the appeal is pending.

Abelman Art Glass vs. Ercana Corporation et al. — On Dec. 13, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed to the 9th Circuit Court of Appeals and oral arguments on the appeal were heard on Feb. 13, 2007.

Sinclair Oil Corporation vs. e prime, inc. and Xcel Energy Inc. — On July 18, 2005, Sinclair Oil Corporation filed a lawsuit against Xcel Energy and its former subsidiary e prime, inc. in the U.S. District Court for the Northern District of Oklahoma alleging liability and damages for purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other natural gas sellers to inflate prices through alleged false reporting of natural gas prices. In response, e prime and Xcel Energy filed a motion with the Multi-District Litigation (MDL) panel to have the matter transferred to U.S. District Judge Pro, who is the judge assigned to western area wholesale natural gas marketing litigation and filed a second motion to dismiss the lawsuit. In response to this motion, this matter was conditionally transferred to U.S. District Court Judge Pro. Judge Pro granted the motion to dismiss, and Sinclair appealed to the Ninth Circuit Court of Appeals. Sinclair’s appeal has been stayed pending the Ninth Circuit’s disposition of the Abelman Art Glass and Texas-Ohio appeals.

Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al. — On June 21, 2005, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California, purportedly in violation of the Sherman Act. This matter has been stayed pending the outcome of cases on appeal to the Ninth Circuit Court of Appeals.

Learjet, Inc. vs. e prime and Xcel Energy et al. — On Nov. 4, 2005, a purported class action complaint was filed in State Court for Wyandotte County of Kansas on behalf of all natural gas producers in Kansas. The lawsuit alleges that e prime, Xcel Energy and other named defendants conspired to raise the market price of natural gas in Kansas by, among other things, inaccurately reporting price and volume information to the market trade publications. On Dec. 7, 2005, the state court granted the defendants motion to remove this matter to the U.S. District Court in Kansas. Plaintiffs have filed a

F-49

motion for remand, which was denied on Aug. 3, 2006. Plaintiffs in this matter and in the J.P. Morgan Trust case, discussed below, have moved the judicial panel on MDL for a separate MDL docket to be set up in Kansas Federal Court. Xcel Energy’s motion to dismiss the complaint is pending.

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. — On Oct. 17, 2005, J.P. Morgan Trust Company, in its capacity as the liquidating trustee for Farmland Industries Liquidating Trust, filed an amended complaint in Kansas State Court adding defendants, including Xcel Energy and e prime, to a previously filed complaint alleging that the defendants inaccurately reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices. The lawsuit was removed to the U.S. District Court in Kansas and subsequently transferred to U.S. District Court Judge Pro in Nevada pursuant to an order from the MDL panel. A motion to remand to state court filed by plaintiffs has been denied. A motion to dismiss plaintiff’s case was granted in December 2006. Plaintiff subsequently filed a motion to amend the judgment and defendents filed an opposition to that motion in February 2007.

Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al. — In May, 2006, Breckenridge Brewery, a Colorado corporation, filed a complaint in Colorado State District Court for the City and County of Denver alleging that the defendants, including e prime and Xcel Energy, unlawfully prevented full and free competition in the trading and sale of natural gas, or controlled the market price of natural gas, and engaged in a conspiracy in constraint of trade. Notice of removal to federal court on behalf of Xcel Energy Inc. and e prime, inc. was filed in June 2006. On July 6, 2006, the Colorado State District Court granted an enlargement of time within which to file a pleading in response to the complaint. Plaintiffs filed a motion to remand the matter to state court, which was denied in October 2006, and the matter has been transferred to U.S. District Court Judge Pro, in Nevada.

Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. — On Oct. 24, 2006, the Missouri Public Utilities Commission filed a complaint in State Court for Jackson County of Missouri alleging that e prime, Xcel Energy and 21 other defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices. The complaint further alleges that such conduct constitutes a violation of the Missouri Antitrust Law, fraud and unjust enrichment. This matter has been removed to U.S. District Court, and plaintiffs have indicated they intend to file a motion to remand to state court. Xcel Energy and e prime deny plaintiffs’ allegations and intend to vigorously defend themselves in this action.

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 on Xcel Energy 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. 22, 2006. The Colorado Court of Appeals is expected to rule on the appeal in 2007.

Fru-Con Construction Corporation vs. Utility Engineering et al. — On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined-cycle power plant in Sacramento County. Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD. UE denies this claim and intends to vigorously defend itself. Because this lawsuit was commenced prior to the April 8, 2005, closing of the sale of UE to Zachry, Xcel Energy is obligated to indemnify Zachry for damages related to this case up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million. On June 1, 2005, UE filed a motion to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement. On Aug. 4, 2005, the court granted UE’s motion to dismiss.

F-50

Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota State District Court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into meaningful settlement negotiations in May 2006, and in August 2006 reached an oral settlement of the dispute. The parties are negotiating over the final form of the settlement documents and it is expected that the action will be formally dismissed in the near future.

Siewert vs. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million. Trial is scheduled to commence in January 2008. NSP-Minnesota denies these allegations and will vigorously defend itself in this matter.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota State District Court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006. In November 2006, the court issued an order denying NSP-Minnesota’s motion. On Nov. 28, 2006, pursuant to a motion by NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful. This certification permits NSP-Minnesota to file an appeal, and it has done so.

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. 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 a 7 day jury trial beginning May 14, 2007.

F-51

Other Contingencies

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.

Energy Efficiency and Renewables Law — On March 17, 2006, Governor Doyle signed into law 2005 Wisconsin Act 141 containing the Governor’s Task Force recommendations on energy efficiency and renewables. The bill sets a statewide renewable portfolio standard (RPS) of 10 percent by 2015 and revises the funding mechanism and administrative responsibilities for the state’s energy efficiency program.

Two rulemaking dockets were subsequently initiated at the PSCW to provide the regulatory framework for administering this statute. Docket 1-AC-220 will create Wisconsin Administrative Code PSC Chapter 137 to establish a structure under which energy utilities collectively establish and fund statewide energy efficiency and renewable resource programs. The funding mechanism will include a contribution from the utilities totaling 1.2 percent of annual operating revenues, which will be fully recoverable in customer rates. Docket 1-AC-221 will revise Wisconsin Administrative Code PSC Chapter 118 that allows for the creation and tracking of renewable resource credits (RRCs). RRCs can be created and used by a utility to meet its renewable obligation under the recently revised RPS, or sold to another utility for its use in meeting its RPS requirement. NSP-Wisconsin anticipates it will be able to meet the RPS with its pro-rata share of existing and planned renewable generation on the NSP System. Both of these rules are expected to be adopted in early 2007.

Energy Legislation — In 2005, the Minnesota Legislature passed and the Governor signed an Omnibus Energy Bill, effective July 1, 2005. Among other things, the new law provides authority for the MPUC to approve rate rider recovery for transmission investments that have been approved through a certificate of need, the biennial transmission plan, or are associated with compliance with the state’s renewable energy objective. The statute provides that the rate rider may include recovery of the revenue requirement associated with qualifying projects, including a current return on construction work in

F-52

progress. NSP-Minnesota’s filing to the MPUC for approval of a new TCR tariff to implement this statute was approved in 2006 and the filing to establish initial TCR rates is pending MPUC approval.

The 2005 Texas Legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the electric reliability council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments. After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by the FERC. In Dec. 2006, PUCT Staff issued a draft rule for comment. The PUCT will initiate a formal rulemaking for this process in 2007.

15. Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes the DOE fuel disposal assessments of approximately $13 million in 2006, $12 million in 2005 and $13 million in 2004. In total, NSP-Minnesota had paid approximately $360 million to the DOE through Dec. 31, 2006. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools at both sites and a dry cask facility at Prairie Island. With the dry cask storage facility licensed by the NRC, approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its current license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the storage pool to continue operations until 2010. In 2005, NSP-Minnesota filed a certificate of need to allow interim storage of spent fuel at the Monticello nuclear plant to support license renewal and operation for an additional 20 years, and in October 2006, the MPUC issued its approval allowing additional interim spent fuel storage. Minnesota Statutes provide that the MPUC decision becomes effective June 1, 2007, which allows the legislature the opportunity to review the MPUC action if desired. All of the alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments for 15 years to 2007. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2006 was $4.9 million; future installments are subject to inflation adjustments under the DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $3.7 million at Dec. 31, 2006, is deferred as a regulatory asset.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the period from cessation of operations through 2050, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143.

Monticello began operation in 1971 with an original license to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. On Sept. 28, 2006, the MPUC approved Xcel Energy’s request for a certificate of need to authorize construction and operation of a dry spent fuel storage facility at Monticello. Minnesota statutes provide that the order is not effective until June 1, 2007. The purpose of

F-53

the stay is to give the state legislature the opportunity to review the MPUC action if lawmakers wish. On Nov. 8, 2006, the NRC renewed the operating license of the Monticello nuclear plant for an additional 20 years to 2030. Plant assessments and other work for the Prairie Island applications started in 2006. The Prairie Island operating license extension for an additional 20 years of operation will be filed in 2008 with the NRC.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in March 2006, using 2005 cost data. The MPUC approval decreasing 2006 decommissioning funding for Minnesota retail customers resulted from an extension of remaining life for the Monticello unit by 10 years (from 2010 to 2020). Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2006, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Current authorized funding presumes that costs will escalate in the future at a rate of 3.61 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.4 percent, net of tax, for external funding. The net unrealized gain on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

In 2006, the Nuclear Decommissioning Trust (NDT) fund also recorded the sale of certain investments in the non-qualified fund and the reinvestment of the proceeds into the qualified fund. The sale and reinvestment, along with the transfer of securities was part of a transaction intended to consolidate trust fund accounts into an income tax advantaged fund, resulting from the Energy Act. The transfer of funds was completed in the fourth quarter of 2006.

At Dec. 31, 2006, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $1.1 billion. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters. Xcel Energy believes future decommissioning cost accruals will continue to be recovered in customer rates. These amounts are not those recorded in the financial statements for the asset retirement obligation in accordance with SFAS No. 143.

	2006			2005
	(Thousands of Dollars)
Estimated decommissioning cost obligation from most recently approved study (2005 and 2002 dollars, respectively)	$	1,683,750		$	1,716,618
Effect of escalating costs to 2006 and 2005 dollars (at 3.61 and 4.19 percent per year, respectively)	60,783			224,946
Estimated decommissioning cost obligation in current dollars	1,744,533			1,941,564
Effect of escalating costs to payment date (at 3.61 and 4.19 percent per year, respectively)	1,382,293			1,851,801
Estimated future decommissioning costs (undiscounted)	3,126,826			3,793,365
Effect of discounting obligation (using risk-free interest rate)	(1,675,114		)	(2,026,003		)
Discounted decommissioning cost obligation	1,451,712			1,767,362
Assets held in external decommissioning trust	1,200,688			1,047,592
Discounted decommissioning obligation in excess of assets currently held in external trust	$	251,024		$	719,770

Decommissioning expenses recognized include the following components:

	2006			2005			2004
	(Thousands of Dollars)
Annual decommissioning cost accrual reported as depreciation expense:
Externally funded	$	48,069		$	80,582		$	80,582
Internally funded (including interest costs)	(5,046		)	(57,561		)	(53,307		)
Net decommissioning accruals recorded	$	43,023		$	23,021		$	27,275

F-54

Negative accruals for internally funded portions in 2004 and 2005 reflect the impact of the 2002 decommissioning study approved in 2003, which approved an assumption of 100-percent external funding of future costs. The 2005 nuclear decommissioning filing approved in 2006 has been used for the regulatory presentation and all the updated parameters were used for the 2005 ARO layer for SFAS No. 143 recognition.

16. Regulatory Assets and Liabilities

Xcel Energy’s regulated businesses prepare their Consolidated Financial Statements 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 Xcel Energy’s business that is not regulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of SFAS No. 71 under GAAP, Xcel Energy 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 of continuing operations shown on the balance sheet at Dec. 31 are:

	See Note(s)		Remaining Amortization Period	2006		2005
	(Thousands of Dollars)
Regulatory Assets
Pension and employee benefit obligations		9	Various	$	475,815	$	27,234
AFDC recorded in plant(a)			Plant lives	179,023		170,785
Conservation programs(a)			Various	124,123		111,429
			Term of related
Contract valuation adjustments(d)		11	contract	109,221		111,639
Losses on reacquired debt		1	Term of related debt	74,420		84,290
Net asset retirement obligations(e)		1,14	Plant lives	54,550		171,170
Renewable resource costs			One to two years	49,902		50,453
Environmental costs		14,15	Generally four to six years	35,715		33,957
Unrecovered natural gas costs(c)		1	One to two years	17,943		12,998
Private fuel storage			Five years	14,473		—
State commission accounting adjustments(a)			Plant lives	13,950		14,460
Unrecovered electric production and MISO Day 2 costs		1	To be determined in future rate proceedings	11,014		6,634
Nuclear decommissioning costs(b)			To be determined in future rate proceedings	9,325		8,317
Rate case costs		1	Various	8,689		4,549
Other			Various	10,982		12,092
Total regulatory assets				$	1,189,145	$	820,007
Regulatory Liabilities
Plant removal costs		1,14		$	920,583	$	895,653
Pension and employee benefit obligations		9		196,803		397,261
Investment tax credit deferrals				78,205		84,437
Deferred income tax adjustments		1		67,002		75,171
Contract valuation adjustments(d)		11		56,745		99,734
Fuel costs, refunds and other				30,032		9,137
Electric fuel recovery refund				10,054		—
Interest on income tax refunds				5,233		6,031
Total regulatory liabilities				$	1,364,657	$	1,567,424

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

(b) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to the DOE assessments, as discussed previously in Note 15.

(c) Excludes current portion expected to be returned to customers within 12 months of $17.7 million and $16.3 million for 2006 and 2005, respectively.

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

(e) Includes amounts recorded for future recovery of asset retirement obligations, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

F-55

17. Segments and Related Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other.

· Xcel Energy’s Regulated Electric Utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. 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 commodity trading operations.

In October 2005, SPS reached a definitive agreement to sell its delivery system operations in Oklahoma, Kansas and a small portion of Texas to Tri-County Electric Cooperative. Effective July 31, 2006, SPS completed the sale to Tri-County Electric Cooperative for $24.5 million and a gain of $6.1 million was recognized. SPS now provides wholesale service to Tri-County Electric Cooperative.

· Xcel Energy’s Regulated Natural Gas Utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and 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, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy 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; and

· 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. Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided.

	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations				Consolidated Total
	(Thousands of Dollars)
2006
Operating revenues from external customers	$	7,608,018	$	2,155,999	$	76,287			$	—		$	9,840,304
Intersegment revenues	820		12,296		—				(13,116		)	—
Total revenues	$	7,608,838	$	2,168,295	$	76,287			$	(13,116	)	$	9,840,304
Depreciation and amortization	$	711,930	$	94,356	$	15,612			$	—		$	821,898
Financing costs, mainly interest expense	302,114		44,965		133,558				(24,605		)	456,032
Income tax expense (benefit)	283,552		37,656		(139,797		)		—			181,411
Income (loss) from continuing operations	$	503,119	$	70,609	$	51,570			$	(56,617	)	$	568,681
2005
Operating revenues from external customers	$	7,243,637	$	2,307,385	$	74,455			$	—		$	9,625,477
Intersegment revenues	767		17,732		—				(18,499		)	—
Total revenues	$	7,244,404	$	2,325,117	$	74,455			$	(18,499	)	$	9,625,477
Depreciation and amortization	$	662,236	$	89,174	$	15,911			$	—		$	767,321
Financing costs, mainly interest expense	301,185		47,145		108,538				(14,242		)	442,626
Income tax expense (benefit)	258,161		32,923		(117,545		)		—			173,539
Income (loss) from continuing operations	$	440,578	$	71,213	$	35,733			$	(48,486	)	$	499,038
2004
Operating revenues from external customers	$	6,225,245	$	1,915,514	$	74,802			$	—		$	8,215,561
Intersegment revenues	1,132		8,735		—				(9,867		)	—
Total revenues	$	6,226,377	$	1,924,249	$	74,802			$	(9,867	)	$	8,215,561
Depreciation and amortization	$	610,127	$	82,012	$	13,816			$	—		$	705,955
Financing costs, mainly interest expense	299,768		48,757		100,784				(14,829		)	434,480
Income tax expense (benefit)	235,743		29,286		(103,094		)		—			161,935
Income (loss) from continuing operations	$	466,307	$	86,091	$	12,173			$	(42,307	)	$	522,264

F-56

18. Summarized Quarterly Financial Data (Unaudited)

Summarized quarterly unaudited financial data is as follows:

	Quarter Ended
	March 31, 2006			June 30, 2006			Sept. 30, 2006			Dec. 31, 2006
	(Thousands of Dollars, except per share amounts)
Revenue		$	2,888,104		$	2,073,873		$	2,411,591		$	2,466,736
Operating income		312,749			224,658			410,103			229,482
Income from continuing operations		149,812			97,936			224,175			96,758
Discontinued operations — income		1,486			339			287			960
Net income		151,298			98,275			224,462			97,718
Earnings available for common shareholders		150,238			97,215			223,402			96,658
Earnings per share from continuing operations — basic		$	0.37		$	0.24		$	0.55		$	0.24
Earnings per share from continuing operations — diluted		$	0.36		$	0.24		$	0.53		$	0.23
Earnings per share from discontinued operations — basic		$	—		$	—		$	—		$	—
Earnings per share from discontinued operations — diluted		$	—		$	—		$	—		$	—
Earnings per share total — basic		$	0.37		$	0.24		$	0.55		$	0.24
Earnings per share total — diluted		$	0.36		$	0.24		$	0.53		$	0.23

	Quarter Ended
	March 31, 2005				June 30, 2005			Sept. 30, 2005				Dec. 31, 2005
	(Thousands of Dollars, except per share amounts)
Revenue		$	2,381,038			$	2,073,549		$	2,288,653			$	2,882,237
Operating income		279,341				198,098			364,725				250,555
Income from continuing operations		127,643				74,613			197,817				98,964
Discontinued operations — income (loss)		(6,165		)		8,793			(1,798		)		13,104
Net income		121,478				83,406			196,019				112,068
Earnings available for common shareholders		120,418				82,346			194,959				111,008
Earnings per share from continuing operations — basic		$	0.32			$	0.18		$	0.49			$	0.25
Earnings per share from continuing operations — diluted		$	0.31			$	0.18		$	0.47			$	0.24
Earnings (loss) per share from discontinued operations — basic		$	(0.02	)		$	0.02		$	(0.01	)		$	0.03
Earnings (loss) per share from discontinued operations — diluted		$	(0.02	)		$	0.02		$	—			$	0.03
Earnings per share total — basic		$	0.30			$	0.20		$	0.48			$	0.28
Earnings per share total — diluted		$	0.29			$	0.20		$	0.47			$	0.27

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 on accounting principles or practices, financial statement disclosures, or auditing scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2006, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and the CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

Internal Controls Over Financial Reporting

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

Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2006 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation

F-57

performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein. Xcel Energy has concluded that the internal control over financial reporting was effective.

Item 9B — Other Information

None.

PART III

Item 10 — Directors, Executive Officers, and Corporate Governance

Information required under this Item with respect to directors is set forth in Xcel Energy’s Proxy Statement for its 2007 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.

Item 11 — Executive Compensation

Information required under this Item is set forth in Xcel Energy’s Proxy Statement for its 2007 Annual Meeting of Shareholders, which is incorporated by reference.

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

Information concerning the security ownership of the directors and officers of Xcel Energy and securities authorized for issuance under equity compensation plans is contained in Xcel Energy’s Proxy Statement for its 2007 Annual Meeting of Shareholders which is incorporated by reference.

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

Information concerning relationships and related transactions of the directors and officers of Xcel Energy is contained in Xcel Energy’s Proxy Statement for its 2007 Annual Meeting of Shareholders, which is incorporated by reference.

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 Xcel Energy’s Proxy Statement for its 2006 Annual Meeting of Shareholders, which is incorporated by reference.

F-58

Part IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements:
	Management Report on Internal Controls — For the year ended Dec. 31, 2006.	66
	Reports of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2006, 2005 and 2004.	F-1
	Consolidated Statements of Income — For the three years ended Dec. 31, 2006, 2005 and 2004.	F-3
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2006, 2005 and 2004.	F-4
	Consolidated Balance Sheets — As of Dec. 31, 2006 and 2005.	F-5
2.	Schedule I — Condensed Financial Information of Registrant.	F-65
	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2006, 2005 and 2004.	F-69
3.	Exhibits

* Indicates incorporation by reference

+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

Xcel Energy

2.01*		Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Co. and New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form 8-K (file no. 001-12907) dated March 24, 1999).
2.02*		Order confirming NRG plan of reorganization dated Nov. 24, 2003 (Exhibit 99.b.10 to Form POS AMC (file no. 070-10152) dated Dec. 1, 2003).
2.03*		Release-Based Amount Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc. (Exhibit 2.03 to Form 10-K (file no. 001-03034) dated March 15, 2004).
2.04*		Settlement Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc. (Exhibit 2.04 to Form 10-K (file no. 001-03034) dated March 15, 2004).
2.05*		Employee Matters Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc. (Exhibit 2.05 to Form 10-K (file no. 001-03034) dated March 15, 2004).
2.06*		Tax Matters Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc. (Exhibit 2.06 to Form 10-K (file no. 001-03034) dated March 15, 2004).
2.07*		Stock Purchase Agreement between Xcel Energy Inc., as “Seller,” and Black Hills Corporation, as “Buyer,” dated Jan. 13, 2004 (Exhibit 99.01 to Form 8-K (file no. 001-03034) dated May 14, 2004).

Xcel Energy

3.01*		Restated Articles of Incorporation of Xcel Energy (Exhibit 4.01 to Form 8-K (file no. 001-03034) filed Aug. 21, 2000).
3.02*		By-Laws of Xcel Energy (Exhibit 3.01 to Form 10-Q (file no. 001-03034) filed Aug. 4, 2004).

Xcel Energy

4.01*		Trust Indenture dated Dec. 1, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000).
4.02*		Supplemental Trust Indenture dated Dec. 15, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee, creating $600 million principal amount of 7 percent Senior Notes, Series due 2010. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000).
4.03*		Stockholder Protection Rights Agreement dated Dec. 13, 2000, between Xcel Energy Inc. and Wells Fargo Bank Rights Agent. (Exhibit 1 to Form 8-K (file no. 001-03034) dated Minnesota, N.A., as Jan. 4, 2001).
4.04*		Registration Rights Agreement dated Nov. 21, 2002 by and among Xcel Energy Inc. and Merrill Lynch, Pierce, Fenner & Smith Inc. and Lazard Freres & Co. LLC. (Exhibit 4.125 to Form 10-K (file no. 001-03034) dated March 31, 2003).
4.05*		Redemption Agreement dated Nov. 25, 2002 by and among Xcel Energy Inc. and the Buyers listed on Exhibit A thereto. (Exhibit 4.136 to Form 10-K (file no. 001-03034) dated March 31, 2003).
4.06*		Indenture dated Nov. 21, 2002 between Xcel Energy Inc. and Wells Fargo Bank NA, 7.5 percent convertible senior notes due 2007 (Exhibit 4.137 to Form 10-K (file no. 001-03034) dated March 31, 2003).
4.07*		Supplemental Trust Indenture No. 2 dated June 15, 2003 between Xcel Energy Inc. and Wells Fargo Bank NA, supplementing trust indenture dated Dec. 1, 2000 (Exhibit 4.01 to Form 10-Q (file no. 001-03034) dated Aug. 15, 2003).
4.08*		Indenture dated Nov. 15, 2003 between Xcel Energy Inc. and Wells Fargo Bank Minnesota NA, 7.5 percent convertible senior notes due 2008. (Exhibit 4.10 to Form 10-K (file no. 001-03034), dated March 15, 2004).
4.09*		Registration Rights Agreement dated June 24, 2003 among Xcel Energy Inc. and Credit Suisse First Boston LLC, McDonald Investments Inc. and UBS Securities LLC (Exhibit 4.10 to Form S-4 (file no. 001-03034) dated Oct. 9, 2003).
4.10*		Registration Rights Agreement dated Nov. 21, 2003 among Xcel Energy Inc., Citadel Equity Fund Ltd., Citadel Credit Trading Ltd., and Citadel Jackson Investment Fund Ltd. (Exhibit 4.10 to Form 10-K (file no. 001-03034), dated March 15, 2004).
4.11*		Form of Stock Option Agreement Dated Aug. 5, 2005 (Exhibit 4.04 to Form S-8 (file no. 001-03034) dated Aug. 5, 2005).

F-59

4.12*		Form of Restricted Stock Agreement Dated Aug. 5, 2005 (Exhibit 4.08 to Form S-8 (file no. 001-03034) dated Aug. 5, 2005).
4.13		Supplemental Trust Indenture dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, National Association as Trustee, creating $300,000,000 principal amount of 6.5 percent Senior Notes, Series due 2036 (Exhibit 4.01 to Current Report on Form 8-K (file no. 001-03034) dated June 6, 2006).
4.14		$800,000,000 Credit Agreement dated Dec. 14, 2006 between Xcel Energy Inc. and various lenders (Exhibit 99.01 to Form 8-K (file no. 001-03034) dated Dec. 14, 2006).

NSP-Minnesota

4.15*		Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034).
		Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.14, dated as follows:
4.16*		July 1, 1989 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated July 7, 1989).
4.17*		June 1, 1990 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 1, 1990).
4.18*		Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992).
4.19*		April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993).
4.20*		Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993).
4.21*		Feb. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Feb. 10, 1994).
4.22*		Oct. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 5, 1994).
4.23*		June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
4.24*		April 1, 1997 (Exhibit 4.47 to Form 10-K (file no. 001-03034) for the year 1997).
4.25*		March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
4.26*		May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.27*		June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.28*		Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.29*		June 1, 2002 (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.30*		June 1, 2002 (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.31*		Aug. 1, 2002 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.32*		Aug. 1, 2003 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.33*		May 1, 2003 (Exhibit 4.73 to Form 10-K (file no. 000-03034) for the year ended Dec. 31, 2003).
4.34*		July 1, 2005 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated July 14, 2005).
4.35*		Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.36*		Supplemental Trust Indenture, dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.37*		Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.38*		Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.39*		Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
4.40*		Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between Northern States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.41*		Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.42*		Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.43*		Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.
4.44*		Underwriting Agreement dated July 14, 2005 between NSP-Minnesota, Barclays Capital Inc. and J.P. Morgan Securities Inc., as representatives of the Underwriters named therein, relating to $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 1.01 to NSP-Minnesota Current Report on Form 8-K, dated July 14, 2005).
4.45*		Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP Minnesota Current Report on Form 8-K, dated July 14, 2005).

F-60

4.46*		Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, dated May 18, 2006).
4.47*		$500,000,000 Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 99.01 to Form 8-K (file no. 000-31387) dated Dec. 14, 2006).

NSP-Wisconsin

4.48*		Supplemental and Restated Trust Indenture, dated March 1, 1991. (Exhibit 4.01K to Registration Statement 33-39831).
4.49*		Supplemental Trust Indenture, dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
4.50*		Supplemental Trust Indenture, dated March 1, 1993. (Exhibit to Form 8-K (file no. 001-03140) dated March 3, 1993).
4.51*		Supplemental Trust Indenture, dated Oct. 1, 1993. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 21, 1993).
4.52*		Supplemental Trust Indenture, dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
4.53*		Trust Indenture dated Sept. 1, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
4.54*		Supplemental Trust Indenture dated Sept. 15, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee, creating $80 million principal amount of 7.64 percent Senior Notes, Series due 2008. (Exhibit 4.02 to Form 8-K (file no 001-03140) dated Sept. 25, 2000).
4.55*		Supplemental Trust Indenture dated Sept. 1, 2003 between Northern States Power Co. (a Wisconsin corporation) and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.56*		Exchange and Registration Rights Agreement dated Oct. 2, 2003 among Northern States Power Co. (a Wisconsin corporation) and Goldman, Sachs & Co. and BNY Capital Markets, Inc. (Exhibit 4.92 to Xcel Energy Form 10-K (file no. 001-03034), dated March 15, 2004)

PSCo

4.57*		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)).
4.58*		Indentures supplemental to Indenture dated as of Oct. 1, 1993:

Dated as of

Previous Filing:
Form; Date or
file no.

Exhibit
No.

Dated as of

Previous Filing:
Form; Date or
file no.

Exhibit
No.

Nov. 1, 1993

S-3, (33-51167)

4(b)(2

)

Aug. 15, 2002

10-Q, Sept. 30, 2002

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, March 15, 2004 (001-03034)

4.100

Aug. 1, 2005

PSCo 8-K, Aug. 18, 2005 (001-03280)

4.02

4.59*		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).
4.60*		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).
4.61*		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).
4.62*		$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).

SPS

4.63*		Indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.64*		First Supplemental Indenture dated March 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.65*		Second Supplemental Indenture dated Oct. 1, 2001 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).

F-61

4.66*		Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and JPMorgan Chase Bank, as successor trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.67*		Fourth Supplemental Indenture dated Oct. 1, 2006 between Southwestern Public Service Co. and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.68*		Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.69*		Registration Rights Agreement dated Oct. 6, 2003 among Southwestern Public Service Co., Citigroup Global Markets Inc. and Credit Suisse First Boston LLC.
4.70*		$250,000,000 Credit Agreement dated Dec. 14, 2006 between SPS and various lenders (Exhibit 99.01 to Form 8-K (file no. 001-03789) dated Dec. 14, 2006).

Xcel Energy

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).
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).

F-62

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).
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, dated as of June 29, 2005, by and between Xcel Energy Inc., a Minnesota corporation, 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 2007.
10.38+		Compensation and reimbursement practices for Xcel Energy non-employee directors.
10.39+		First Amendment to the Xcel Energy Senior Executive Severance and Change-In-Control Policy dated Oct. 25, 2006.

NSP-Minnesota

10.39*		Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (KV) line.v (Exhibit 5.06I to file no. 2-54310).
10.40*		Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06J to file no. 2-54310).
10.41*		Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06K to file no. 2-54310).
10.42*		Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.43*		Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.44*		Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.45*		Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 of NSP-Minnesota, file no. 000-31709).
10.46*		Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.47*		Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1, file no. 333-35096).
10.48*		Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, file no. 333-35096).
10.49*		Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.50*		500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no.001-31387) dated March 25, 2003).

NSP-Wisconsin

10.51*

Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).

PSCo

10.52*		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)).
10.53*		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)).
10.54*		Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).

F-63

10.55*

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).

SPS

10.56*		Coal Supply Agreement (Harrington Station) between Southwestern Public Service Co. and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
10.57*		Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
10.58*		Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
10.59*		Coal Supply Agreement (Tolk Station) between Southwestern Public Service Co. and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
10.60*		Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
10.61*		Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and Southwestern Public Service Co.

Xcel Energy

12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
21.01		Subsidiaries of Xcel Energy Inc.
23.01		Consent of Independent Registered Public Accounting Firm.
24.01		Written Consent Resolution of the Board of Directors of Xcel Energy Inc., adopting Power of Attorney
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.

F-64

SCHEDULE I

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.

Statements of Income

	Year ended Dec. 31,
	2006				2005				2004
	(Thousands of Dollars)
Income:
Equity in income of subsidiaries		$	625,298			$	547,524			$	564,572
Total income		625,298				547,524				564,572
Expenses and other deductions:
Operating expenses		9,143				9,151				27,588
Other income		(8,980		)		(6,047		)		(4,800		)
Interest charges and financing costs		107,778				87,804				74,608
Total expenses and other deductions		107,941				90,908				97,396
Income from continuing operations before taxes		517,357				456,616				467,176
Income tax benefit		(51,324		)		(42,422		)		(55,088		)
Income from continuing operations		568,681				499,038				522,264
Income from discontinued operations, net of tax		3,073				13,934				(166,303		)
Net income		571,754				512,972				355,961
Preferred dividend requirements		4,241				4,241				4,241
Earnings available to common stockholders		$	567,513			$	508,731			$	351,720

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

F-65

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.

Statements of Cash Flows

(thousands of Dollars)

	Years Ended Dec. 31
	2006				2005				2004
Operating Activities:
Net cash provided by (used in) operating activities		$	634,128			$	391,776			$	(19,607	)
Investing Activities:
Return of capital from subsidiaries		201,185				262,378				318,625
Capital contributions to subsidiaries		(576,600		)		(504,402		)		(367,763		)
Restricted cash		—				—				37,213
Net cash used in investing activities		(375,415		)		(242,024		)		(11,925		)
Financing Activities:
Short-term borrowings — net		(211,716		)		325,516				—
Proceeds from issuance of long-term debt		294,830				484,824				420,616
Repayment of long-term debt		—				(625,000		)		(281,000		)
Proceeds from issuance of common stock		16,275				9,085				6,985
Common stock repurchase		—				—				(32,023		)
Dividends paid		(358,746		)		(343,092		)		(320,444		)
Net cash used in financing activities		(259,357		)		(148,667		)		(205,866		)
Net increase (decrease) in cash and cash equivalents		(644		)		1,085				(237,398		)
Cash and cash equivalents at beginning of year		1,167				82				237,480
Cash and cash equivalents at end of year		$	523			$	1,167			$	82

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

F-66

Condensed Financial Statements of Xcel Energy Inc.

Balance Sheets

(thousands of dollars)

	2006			2005
Assets
Cash and cash equivalents		$	523		$	1,167
Accounts receivable from subsidiaries		171,434			214,271
Other current assets		26,443			30,542
Total Current Assets		198,400			245,980
Investment in subsidiaries		7,261,515			6,644,114
Other assets		39,998			76,067
Noncurrent assets related to discontinued operations		40,152			80,101
Total Other Assets		7,341,665			6,800,282
Total Assets		$	7,540,065		$	7,046,262
Liabilities and Equity
Current liabilities related to discontinued operations		$	358		$	10,128
Dividends payable		91,685			87,788
Short term debt		343,800			325,516
Other current liabilities		29,257			16,741
Total Current Liabilities		465,100			440,173
Other liabilities		23,476			42,123
Total Other Liabilities		23,476			42,123
Long-term debt		1,129,687			1,063,731
Preferred stockholders’ equity		104,980			104,980
Common stockholders’ equity		5,816,822			5,395,255
Total Capitalization		7,051,489			6,563,966
Total Liabilities and Equity		$	7,540,065		$	7,046,262

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

F-67

NOTES TO CONDENSED FINANCIAL STATEMENTS

Incorporated by reference are Xcel Energy Inc. and Subsidiaries Consolidated Statements of Common Stockholder’s Equity and Other Comprehensive Income in Part II, Item 8.

Basis of Presentation — The condensed financial information the holding company of Xcel Energy is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.

Cash dividends paid to Xcel Energy by subsidiaries were $759 million, $566 million, and $853 million in the three years ended December 31, 2006, respectively.

See Xcel Energy Inc. Notes to the Consolidated Financial Statements in Part II, Item 8 for other disclosures.

F-68

SCHEDULE II

XCEL ENERGY INC.

And Subsidiaries
Valuation and Qualifying Accounts
Years Ended Dec. 31, 2006, 2005 and 2004

(thousands of dollars)

				Additions
	Balance at beginning of period			Charged to costs & expenses			Charged to other accounts(1)			Deductions from reserves(2)			Balance at end of period
Reserve deducted from related assets:
Provision for uncollectible accounts:
2006		$	39,798		$	56,919		$	16,022		$	76,050		$	36,689
2005		$	34,299		$	43,327		$	12,379		$	50,207		$	39,798
2004		$	30,727		$	33,831		$	11,095		$	41,354		$	34,299

(1) Recovery of amounts previously written off.

(2) Principally uncollectible accounts written off or transferred.

F-69

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.

	XCEL ENERGY INC.
February 22, 2007	By:	/s/ BENJAMIN G.S. FOWKE III
		Benjamin G.S. Fowke III Vice President and Chief Financial Officer (Principal Financial Officer)

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

	/s/ RICHARD C. KELLY		Chairman, President and Chief Executive Officer
	Richard C. Kelly		(Principal Executive Officer)
	/s/ TERESA S. MADDEN		Vice President and Controller
	TERESA S. MADDEN		(Principal Accounting Officer)
	/S/ BENJAMIN G.S. FOWKE III		Vice President and Chief Financial Officer
	BENJAMIN G.S. FOWKE III		(Principal Financial Officer)

*		Director
	FREDRIC W. CORRIGAN
*		Director
	ROGER R. HEMMINGHAUS
*		Director
	DOUGLAS W. LEATHERDALE
*		Director
	MARGARET R. PRESKA
*		Director
	RICHARD H. TRULY
*		Director
	DAVID A. WESTERLUND
*		Director
	C. CONEY BURGESS
*		Director
	A. BARRY HIRSCHFELD
*		Director
	ALBERT F. MORENO

F-70

*		Director
	A. PATRICIA SAMPSON
*		Director
	RICHARD K. DAVIS
*		Director
	TIMOTHY V. WOLF

*	/s/ TERESA S. MADDEN
	TERESA S. MADDEN Attorney-in-Fact

F-71

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	6th grade Avg

Xcel Energy (XEL) 10-K2006 FY Annual report

Content analysis