10-K 1 a2182843z10-k.htm FORM 10-K
QuickLinks -- Click here to rapidly navigate through this document



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)  

ý

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

For the Fiscal Year Ended Dec. 31, 2007

Or

 

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
(State or Other Jurisdiction of
Incorporation or Organization)
  41-0448030
(I.R.S. Employer Identification No.)

414 Nicollet Mall,
Minneapolis, Minnesota

(Address of Principal Executive Offices)

 

55401
(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   New York
    Cumulative Preferred Stock, $100 par value:    
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
Xcel Energy Inc.   7.60 Junior Subordinated Notes, Series due 2068   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. Yes ý 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. Yes o No ý

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

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Act. (Check one): ý Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller Reporting Company

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

        As of June 30, 2007, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $8,587,360,038 and there were 419,509,528 shares of common stock outstanding. Yes o No ý

        As of Feb. 14, 2008, there were 429,147,979 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

        The Registrant's Definitive Proxy Statement for its 2008 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.





TABLE OF CONTENTS

Index

PART I   Item 1 —   Business   3
              DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS   3
            COMPANY OVERVIEW   7
            ELECTRIC UTILITY OPERATIONS   10
                Electric Utility Trends   10
                NSP-Minnesota   12
                NSP-Wisconsin   19
                PSCo   20
                SPS   24
                Electric Operating Statistics    
          NATURAL GAS UTILITY OPERATIONS   28
                Natural Gas Utility Trends   28
                NSP-Minnesota   28
                NSP-Wisconsin   29
                PSCo   30
                Natural Gas Operating Statistics    
          ENVIRONMENTAL MATTERS   32
          CAPITAL SPENDING AND FINANCING   33
          EMPLOYEES   33
          EXECUTIVE OFFICERS   33
    Item 1A —   Risk Factors   35
    Item 1B —   Unresolved SEC Staff Comments   40
    Item 2 —   Properties   41
    Item 3 —   Legal Proceedings   43
    Item 4 —   Submission of Matters to a Vote of Security Holders   43
PART II   Item 5 —   Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   44
    Item 6 —   Selected Financial Data   45
    Item 7 —   Management's Discussion and Analysis of Financial Condition and Results of Operations   46
    Item 7A —   Quantitative and Qualitative Disclosures about Market Risk   73
    Item 8 —   Financial Statements and Supplementary Data   74
    Item 9 —   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   145
    Item 9A —   Controls and Procedures   145
    Item 9B —   Other Information   145
PART III   Item 10 —   Directors, Executive Officers, and Corporate Governance   145
    Item 11 —   Executive Compensation   145
    Item 12 —   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   145
    Item 13 —   Certain Relationships, Related Transactions, and Director Independence   146
    Item 14 —   Principal Accounting Fees and Services   146
PART IV   Item 15 —   Exhibits, Financial Statement Schedules   147
SIGNATURES   158

2



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
NCE   New Century Energies, Inc.
NRG   NRG Energy, Inc., a Delaware corporation and independent power producer
NMC   Nuclear Management Company, a wholly owned subsidiary of NSP Nuclear Corporation
NSP-Minnesota   Northern States Power Company, a Minnesota corporation
NSP-Wisconsin   Northern States Power Company, a Wisconsin corporation
PSCo   Public Service Company of Colorado, a Colorado corporation
PSRI   PSR Investments, Inc., a manager of corporate-owned 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
WYCO   WYCO Development LLC
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
EPA   United States Environmental Protection Agency
FERC   Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS   Internal Revenue Service
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.
NERC   North American Electric Reliability Council
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

3



Electric, Purchased Gas and Resource Adjustment Clauses

 

 

 

 
AQIR   Air-quality improvement rider. Recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
DSM   Demand-side management. Energy conservation, 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, 2007, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. It encourages cost reductions through purchases of economical short-term energy. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. 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.
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 Dec. 31, 2010. The QSP for the PSCo natural gas utility expires December 2007.
SCA   Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
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
CO2   Carbon dioxide
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

4


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.
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).
GHG   Greenhouse Gas
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.
NOx   Nitrogen oxide
nonutility   All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
PBRP   Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
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.
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 of MISO
TCEQ   Texas Commission of Environmental Quality

5


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
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
GWh   Gigawatt hours
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)
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.

6



COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2007, Xcel Energy's continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in eight 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 WYCO, a company formed to develop and lease new natural gas pipeline and compression facilities, and 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 and 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 are also available on its web site.

As discussed in detail in the Management's Discussion and Analysis section, environmental leadership is a core strategic priority for Xcel Energy. Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value. We have established a highly effective environmental compliance program and have produced an excellent compliance record. Moreover, we pursue environmental policy initiatives that promote our environmental leadership and provide growth opportunities. Among other things, Xcel Energy is a national leader in voluntary emission reduction programs, the nation's largest retail utility wind energy provider and a leader in innovative technology, energy efficiency and conservation and customer-driven renewable energy programs. In 2007, Xcel Energy filed resource plans in two of its operating service territories that will result in a significant reduction in CO2 emissions, while meeting growing customer demand at a reasonable price. Through our environmental leadership strategy, we are well-positioned to meet the challenges of potential future climate change regulation, comply with the renewable energy mandates and take advantage of the clean energy incentives created by policy makers in the states in which we operate.


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 10 percent of the total sales in 2007. 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 were derived from operations in Minnesota during 2007. Generally, NSP-Minnesota's earnings comprise approximately 40 percent to 50 percent of Xcel Energy's consolidated net income.

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 owns 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, distribution and sale of electricity 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 the total sales in 2007. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory. NSP-Wisconsin provides electric utility service to approximately 246,000 customers and natural gas utility service to approximately

7


102,000 customers. The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota, as discussed previously. Approximately 98 percent of NSP-Wisconsin's retail electric operating revenues were derived from operations in Wisconsin during 2007. Generally, NSP-Wisconsin's earnings comprise approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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 in Colorado. The wholesale customers served by PSCo comprised approximately 24 percent of the total sales in 2007. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility and natural gas utility service to approximately 1.3 million customers. All of PSCo's retail electric operating revenues were derived from operations in Colorado during 2007. Generally, PSCo's earnings comprise approximately 40 percent to 50 percent of Xcel Energy's consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; and Green and Clear Lakes Company, which owns water rights. PSCo also owned PSRI, which held certain former employees' life insurance policies. Following settlement with the IRS during 2007, such policies were terminated. PSCo also holds a controlling interest in several other relatively small ditch and water companies.


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 in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 38 percent of the total sales in 2007. SPS provides electric utility service to approximately 388,000 customers. Approximately 76 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2007. Generally, SPS' earnings comprise approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.


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 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 $151 million in WYCO between 2007 and 2010. 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 for 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 Services Inc. is the service company for the Xcel Energy holding company system, where corporate financing activity occurs. Generally, Xcel Energy Services, Inc.'s losses comprise approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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

See financial information regarding the segments of Xcel Energy's business at Note 18 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 3 to the consolidated financial statements.

8


Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. Comparative segment revenues, income from continuing operations and related financial information for fiscal years 2007, 2006 and 2005 are set forth in Note 18 to the accompanying consolidated financial statements.

Xcel Energy focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers. Xcel Energy files periodic 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 15 to the consolidated financial statements.

9



ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

Climate Change and Clean Energy  Like most other utilities, Xcel Energy is subject to a significant array of environmental regulations focused on many different aspects of its operations. There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. Xcel Energy's electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. Several of the states in which we operate have proposed or implemented clean energy policies, such as renewable energy portfolio standards or DSM programs, in part designed to reduce the emissions of GHGs. Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies. Xcel Energy is advocating with state and federal policy makers for climate change and clean energy policies that will result in significant long-term reduction in GHG emissions, develop low-emitting technologies and secure, cost-effective energy supplies for our customers and our nation.

While Xcel Energy is not currently subject to state or federal limits on its GHG emissions, we have undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on Xcel Energy will depend on the specifics of state and federal policies and legislation, we believe that, based on prior state commission practice, we would be granted the authority to recover the cost of these initiatives through rates.

Additional information regarding climate change and clean energy is presented in the Management's Discussion and Analysis section.

Utility Restructuring and Retail Competition  The FERC has continued with its efforts to promote more competitive wholesale markets through open-access transmission and other means. As a consequence, Xcel Energy's utility subsidiaries and their wholesale customers can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries' to serve their native load.

Xcel Energy supports 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 Texas 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.

One state served by Xcel Energy's utility subsidiaries has implemented retail electric utility competition. In 2002, Texas 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. Local market conditions and political realities must be considered in proposing the transition to competition. Xcel Energy has been unable to develop a plan for the Texas Panhandle to move toward competition that would be in the best interests of its customers. As a result, Xcel Energy does not plan to propose retail competition in the Texas Panhandle until required by law. New Mexico repealed its legislation related to retail electric utility competition.

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.

Xcel Energy's retail electric business faces competition as industrial and large commercial customers have the 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 faces these challenges, their rates are competitive with currently available alternatives.

10




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 14 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act)  The Energy Act repealed PUHCA effective Feb. 8, 2006. 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 August 2005, the FERC has completed several rulemaking proceedings to modify its regulations on a number of subjects, including:

Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary NERC structure, and requiring the ERO to establish mandatory electric reliability standards and imposition of financial or other penalties for violations of adopted standards;

Certifying the NERC as the ERO and adopting rules making 83 NERC reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance effective June 18, 2007; and approving delegation agreements between NERC and various regional entities, including the Midwest Reliability Organization (MRO), SPP and Western Electricity Coordinating Council (WECC), whereby the regional entities will be responsible for regional enforcement of approved NERC standards. On Dec. 21, 2007, the FERC approved seven additional NERC mandatory standards to be effective in first quarter 2008;

Adopting rules allowing utilities in organized wholesale energy markets such as MISO and SPP to seek to eliminate their mandatory Public Utility Regulatory Policies Act (PURPA) QF power purchase obligations; and

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

During 2007, both state and federal legislative initiatives were introduced, with the Xcel Energy subsidiaries taking an active role in their development.

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

Electric Transmission Rate Regulation  The FERC regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control of their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO. NSP-Minnesota and NSP-Wisconsin are members of the MISO RTO. SPS is a member of the SPP RTO. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates. PSCo is currently participating with other utilities in the development of WestConnect, which would provide certain regionalized transmission and wholesale energy market functions but would not be an RTO.

On Feb. 15, 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules. Xcel Energy submitted the required compliance revisions to its Open Access Transmission Tariff (OATT) on July 13, 2007, Sept. 11, 2007 and Dec. 7, 2007, as required. The compliance filings are pending FERC action. On Dec. 28, 2007, the FERC issued an order on rehearing making certain modifications to Order No. 890. The revised rules will be effective in March 2008. Xcel Energy is now reviewing the amended final rules.

In addition, in January 2007, the FERC issued interim and proposed rules to modify the current FERC standards of conduct rules governing the functional separation of the Xcel Energy electric transmission function from the wholesale sales and marketing function. The proposed rules are pending final FERC action.

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

Centralized Regional Wholesale Markets  The FERC rules allow RTOs to operate centralized regional wholesale energy markets. On April 1, 2005, MISO began operation of a "Day 2" regional day-ahead and real time wholesale energy market. 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

11



dispatch over the 15 state MISO region, including the NSP System. In 2007, SPP began operation of an Energy Imbalance Service (EIS) market, which will provide a more limited wholesale energy market for the region that includes the SPS system.

On Sept. 14, 2007, MISO filed for FERC approval to establish a centralized regional wholesale ancillary services market (ASM) in the second quarter of 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market. In addition, MISO would consolidate the operation of approximately 20 existing NERC approved balancing authorities (the entity responsible for maintaining reliable operations for a defined geographic region) into a single regional balancing authority. Xcel Energy generally supports implementation of the ASM, because it is expected to allow native NSP System generation to be used more efficiently, as certain generation will not always need to be held in reserve, and to facilitate the operation of intermittent wind generation on the NSP System required to achieve state-mandated renewable energy supply standards. Comments on the ASM proposal were filed on Oct. 15, 2007, and the FERC held a technical conference on certain market power issues in November 2007. The proposal is pending FERC action. If the FERC approves the ASM tariff in February 2008 without material conditions, and if MISO can demonstrate system and operation readiness, MISO would implement the ASM on June 1, 2008. If approved by the FERC, NSP-Minnesota and NSP-Wisconsin expect to file for state regulatory approvals, as necessary, to recover ASM costs via their fuel and purchased energy cost recovery mechanisms in first quarter 2008.

In another development affecting regional wholesale markets, in December 2007, MISO and some MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed proposed changes to the MISO TEMT affecting the revenue distribution of transmission revenues. Without the proposed tariff change, certain MISO transmission owners would experience an increase in prospective transmission revenues, while the revenues to other MISO transmission owners would correspondingly decrease. The proposed change did not affect 2007 results, but would essentially preserve the historic allocation of transmission service revenues in 2008 and future years. In December 2007, Ameren-Union Electric (Ameren UE) protested the proposed change. In February 2008, the FERC issued an order accepting the MISO tariff change effective February 2008 and rejecting the Ameren-UE protest.

Market Based Rate Rules  In June 2007, the FERC issued a final order governing its market-based rate authorizations to electric utilities. The FERC reemphasized its commitment to market-based pricing, but is revising the tests it uses to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has market-based rate authorizations. Each of the Xcel Energy operating companies has been granted market-based rate authority and will be subject to the new rule.

An aspect of the FERC's market-based rate requirements is the requirement to charge mitigated rates in markets where a utility is found to have market power. PSCo and SPS have been authorized by the FERC to charge market-based rates outside of their control areas, but are generally limited to charging mitigated rates within their control areas. PSCo and SPS use cost-based rate caps set out in the Western Systems Power Pool (WSPP) agreement as their applicable mitigated rates, an approach approved by the FERC. However, concurrently with the issuance of the final order, the FERC initiated a proceeding to investigate whether the use of the WSPP rate caps for this purpose is just and reasonable. An outcome of this proceeding may be to lower the mitigated rates that PSCo and SPS may charge in their control areas.


NSP-Minnesota

Public Utility Regulation

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.

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.

12


NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, 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 RTO.

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. 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. While this law will change to a savings-based requirement beginning in 2010, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.

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 first MERP project at the A. S. King plant went into service in July 2007 with the remaining two projects (High Bridge and Riverside) expected to begin operations in 2008 and 2009, respectively, 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, 2007, the estimated ROE was 10.7 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 2008, assuming normal weather, are listed below.

 
  System Peak Demand (in MW)
 
  2005
  2006
  2007
  2008 Forecast
NSP System   9,104   9,859   9,427   9,737

The peak demand for the NSP System typically occurs in the summer. The 2007 system peak demand for the NSP System occurred on July 26, 2007.


Energy Sources and Related Transmission Initiatives

NSP-Minnesota expects to use existing electric generating stations, power purchases, DSM options, new generation facilities and phased expansion of existing generation at select power plants to meet its system capacity requirements.

13


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

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 and for various other operating requirements.

Purchased Transmission Services  In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO and regional transmission service providers to deliver power and energy to the NSP System for native load customers, which are retail and wholesale load obligations with terms of more than one year.

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

The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior's petition. The contested case proceeding considered a 600 MW unit in phase I and a second 600 MW unit in phase II of the Mesaba Energy Project.

The MPUC issued its order for phase 1 of the hearing on Aug. 30, 2007. In it, the MPUC found that:

The Mesaba Energy Project is an innovative energy project under the applicable statute;

The terms and conditions of the proposed purchase power agreement are inconsistent with the public interest and are denied;

Excelsior and NSP-Minnesota should resume negotiations towards an acceptable purchase power agreement, with assistance from the Minnesota Department of Commerce (MDOC) and the guidance provided by the order; and

The MPUC will explore a statewide market for the output of this project.

The MPUC denied rehearing, except for certain clarifications and requiring status reports on negotiations Excelsior appealed the MPUC's decision in December 2007. The Minnesota Court of Appeals dismissed the appeal as premature because the MPUC's order on phase I is not final agency action on the entire case.

Meanwhile, the ALJ issued a decision in Phase 2 of this proceeding, recommending denial of Excelsior's proposed purchase power agreement for a second IGCC project. Exceptions and replies have been filed. The MPUC is expected to take up this matter in 2008.

Greenhouse Gas Emissions  The 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors producing those emissions to a level at least 15 percent below 2005 levels by 2015, to a level at least 30 percent below 2005 levels by 2025, and to a level at least 80 percent below 2005 levels by 2050.

The legislation prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO2 emissions. The statute does not impose limitations on CO2 or other GHG emissions on NSP-Minnesota and provided certain exemptions. On Feb. 1, 2008, the MDOC submitted to the legislature a climate change action plan that proposes certain changes to meet the requirements of this section.

Renewable Energy Standard  The 2007 Minnesota legislature adopted a Renewable Energy Standard (RES) statute requiring NSP-Minnesota to acquire 30 percent of its energy requirements by 2020 from qualifying renewable sources, of which 25 percent must be wind energy. The legislation allows all NSP-Minnesota renewable resources to count toward meeting the standard. Costs associated with complying with the standard are recoverable through automatic recovery mechanisms.

14


NSP-Minnesota has filed with the MPUC a renewable energy plan detailing its plans for adding wind resources. This plan seeks to achieve balance in the wind portfolio, with roughly half of new resources being owned by NSP-Minnesota and achieving roughly proportionate shares between community-based energy developments, other power purchase agreements and utility projects.

Conservation and DSM Legislation  The 2007 Minnesota legislature adopted a statute establishing a statewide goal to reduce energy demand by 1.5 percent per year and fossil fuel use by 15 percent. The bill requires utilities to propose conservation and DSM programs that achieve at least 1.0 percent per year reduction in energy demand, subject to limitations regarding excessive costs for customers, reliability or other negative consequences. The statute also allows utilities to fund internal infrastructure changes that will contribute to lower energy use and provides for cost recovery outside a rate case for such projects.

NSP System Resource Plan  In December, 2007, NSP-Minnesota filed its 2007 resource plan with the MPUC. The plan incorporates the actions needed to comply with expansive new legislation regarding GHG emissions control, renewable energy procurement, and DSM adopted by the 2007 Minnesota legislature. Due to the expansion of wind generation procurement and DSM obligations, the plan indicates that the type of incremental resources has changed from prior plans. Key highlights of the plan include:

Additional wind generation resources of 2,600 MW, allowing NSP-Minnesota to comply with our RES of 30 percent renewable energy by 2020.

Increases in DSM of approximately 30 percent energy savings and 50 percent demand savings.

Seek license renewals for Prairie Island's two units through 2033 and 2034, respectively, and expand capacity at Prairie Island by 160 MW and Monticello by 71 MW.

Request approval to make environmental upgrades at Sherco, while expanding capacity by 80 MW. The environmental upgrades would result in a significant reduction in overall SO2, NOx and mercury emissions from the facility.

Negotiate and seek approval of purchases from Manitoba Hydro Electric Board (Manitoba Hydro) for 375 MW of intermediate and 350 MW of peaking resources beginning in 2015.

Incremental peaking and intermediate generation needs of 2,300 MWs.

Carbon emission reductions of 22 percent below 2005 levels by 2020, a six million ton reduction.

The MPUC will set a schedule for consideration of the plan early in 2008.

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 2015-2025 and the purchase of 380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan. An alternate supplier proposed a 375 MW share of a lignite coal generation plant to be located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both components. The MPUC referred the matter to a contested case proceeding.

On July 20, 2007, NSP-Minnesota filed a petition asking to suspend the proceeding until NSP-Minnesota can complete its analysis of the impact of the RES and conservation goals on its need for additional resources, as outlined in the July 20, 2007 Notice of Changed Circumstance in the Resource Plan.

In September 2007, the MPUC approved NSP-Minnesota's Notice of Changed Circumstance and required NSP-Minnesota to file a new resource plan by Dec. 14, 2007. NSP-Minnesota filed the 2007 resource plan, along with a proposal for closing this proceeding as the new plan does not indicate a base load resource need. The MPUC is expected to take up matter of schedule for the base load proceeding in early 2008.

Additional Base Load Capacity Projects for Sherco, Monticello and Prairie Island  The MPUC order in the 2004 NSP-Minnesota resource plan indicated that additional capacity from the Sherco, Monticello, and Prairie Island plants would be cost-effective and should be pursued. On July 20, 2007, NSP-Minnesota filed a Notice of Changed Circumstance with the MPUC seeking to delay these proceedings until NSP-Minnesota can complete its analysis of the impact of the RES and conservation goals on its need for additional resources. In September 2007, MPUC approved the Notice of Changed Circumstance and directed NSP-Minnesota to file a new resource plan by Dec. 14, 2007. NSP-Minnesota filed the 2007 resource plan, which confirms the cost-effectiveness of these projects, and proposed to initiate filings for approval to pursue these projects in the first half of 2008.

15


NSP-Minnesota Transmission Certificates of Need  In March 2003, the MPUC granted four certificates of need to NSP-Minnesota for the construction of various transmission system upgrades for up to 825 MW of renewable energy generation (wind and biomass) in southwest and western Minnesota.

The MPUC granted routing permits in 2004-05 for the major transmission facilities. NSP-Minnesota expects to complete the transmission construction in 2008 at a cost of approximately $230 million. As of Dec. 20, 2007, MISO has determined the new transmission facilities already installed provide transmission outlet capacity for up to 900 MW of renewable generation.

In late 2006, NSP-Minnesota filed applications for certificates of need with the MPUC for three additional transmission lines in southwestern Minnesota and one in Chisago County, Minn. In 2007, the MPUC issued a certificate of need authorizing NSP-Minnesota to construct three new 115 KV transmission lines (totaling 35 to 50 miles) in southwestern Minnesota to provide approximately 350 MW of incremental transmission delivery capacity for wind generation. The three projects, including associated substations, are expected to cost $72.5 million. The MPUC order required NSP-Minnesota to file required route permit applications by January 2008 and complete construction by Spring 2009. The route permit applications were filed with the MPUC and SDPUC as required, and are pending MPUC and SDPUC action.

In January 2008, the MPUC voted to grant NSP-Minnesota a certificate of need for the Chisago County, Minnesota project, which would replace an existing 69 KV line with 115 and 161 KV facilities and add a new substation at an estimated cost of $64 million and a route permit for the majority of the proposed line. The MPUC set the issue of the disputed route for a half-mile segment of the line for further discussions between the parties. The project would be placed in service in 2010. The PSCW has already approved construction by NSP-Wisconsin and Dairyland Power Cooperative of related 161 KV facilities in Wisconsin.

As part of CapX 2020, NSP-Minnesota and Great River Energy (on behalf of nine other regional transmission providers) filed a certificate of need application in August 2007, for three 345 KV transmission lines serving Minnesota and parts of surrounding states. The current schedule targets an MPUC order by the end of 2008 or early 2009. The three lines would include construction of approximately 700 miles of new facilities at a cost of $1.4 to $1.7 billion, with construction to be completed in phases between 2011 and 2015. The application put forth a potential ownership percentage of 36 to 72 percent for each of the three 345 KV projects for NSP System. Updated NSP-Minnesota and NSP-Wisconsin cost estimates are expected following the negotiation of project agreements outlining the terms and conditions related to construction management, ownership, operations and maintenance of these facilities.

FCA Investigation  In 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCAs for electric utilities in Minnesota. There was no further activity until the MPUC issued a notice for comments on April 5, 2007, as to whether to continue the statewide investigation.

Pursuant to the notice, utilities in Minnesota, the MDOC and the Minnesota Office of Attorney General (MOAG) filed initial and reply comments on April 30, 2007 and June 1, 2007, respectively. The utilities generally argued the 2003 investigation could be closed, with remaining issues addressed in the separate investigation initiated by the Dec. 20, 2006 order in the MISO Day 2 cost recovery docket. The MDOC filed comments seeking to continue the investigations. In response, the utilities filed additional comments on Sept. 28, 2007, that indicated a willingness to continue with the investigation and provide more information to both regulators and customers regarding fuel and purchased power costs, plant outages and other factors affecting fuel clause levels. Continued discussions among utilities, the MDOC, MOAG and business customers regarding appropriate FCA reporting detail and provision of additional information to customers is on going.

Grand Meadow Wind Farm  In June 2007, NSP-Minnesota filed an application for a certificate of need for the Grand Meadows wind farm, a 100-MW development to be located in southeast Minnesota. The Grand Meadows project would be implemented under a build-own-transfer agreement between NSP-Minnesota and enXco, a wind project developer. Total project costs are estimated to be approximately $213 million. The MPUC approved this certificate of need and issued a site permit. Construction is expected to start in early 2008.

Capital Structure Petition  In December 2007, the MPUC approved NSP-Minnesota's regular annual capital structure petition for ongoing security issuance and increased capitalization.

Mercury Reduction and Emissions Reduction Filings  Pursuant to Minnesota law, in December 2007, NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercury emissions by up to 90 percent at the Sherco unit 3 and King plants. Estimated project costs amount to approximately $9.1 million. At the same time, NSP-Minnesota

16



submitted a revised filing to the MPUC for a major emissions reduction project at Sherco Units 1and 2 to reduce emissions and expand capacity. The revised filing has estimated project costs of approximately $1.1 billion. The filing also contains alternatives for the MPUC to consider additional capacity and to achieve lower emissions. If selected, these alternatives could range from $90.8 million to $330.8 million in addition to the $1.1 billion proposal. NSP-Minnesota's investments are subject to the MPUC approval of a cost recovery mechanism.

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 16 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 low-level radioactive waste (LLW) generated within its borders. LLW from NSP-Minnesota's Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of LLW) and at the Clive facility located in Utah (class A LLW only). NSP-Minnesota has an annual contract with Barnwell that is scheduled to expire on June 30, 2008, but is also able to utilize the Clive facility through various LLW processors. NSP-Minnesota has 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 LLW 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.

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. The MPUC decision was effective June 1, 2007.

As of Dec. 31, 2007, there were 24 casks loaded and stored at the Prairie Island plant.

See Note 16 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. In February 2006, the NRC commissioners issued the license for PFS. 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

17



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 refueling outage.

NSP-Minnesota Nuclear Plant Re-licensing — Monticello's renewed license expires in 2030, and Prairie Island's licenses for its two units expire in 2013 and 2014. NRC approved Monticello's renewed license in November 2006, and the MPUC order approving additional spent fuel storage to support twenty additional years of operation went into effect on June 1, 2007. 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 — NSP-Minnesota is seeking approval to increase the capacity of all three nuclear units that will total approximately 235 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. Capital investments for life cycle management and power uprate activities through 2007 have totaled approximately $40 million. For the years 2008 through 2015, spending is estimated at $1.1 billion. 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 and the certificate of need for the Prairie Island uprate in the first quarter of 2008.

NMC — On Sept. 28, 2007, Xcel Energy obtained 100 percent ownership in NMC as a result of Wisconsin Energy Corporation (WEC) exiting the partnership due to the sale of its Point Beach Nuclear Plant to FPL Energy. Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were consolidated in Xcel Energy's consolidated financial statements from the Sept. 28, 2007, transaction date. WEC was required to pay an exit fee and surrender all of its equity interest in NMC upon exiting. The effect of this transaction was not material to the financial position or the results of operations to Xcel Energy. Xcel Energy is in the process of reintegrating its nuclear operations into its generation operations and applying to the NRC to transfer the nuclear operating licenses from NMC to NSP-Minnesota. The transfer of licenses is expected to be completed in 2008.

For further discussion of nuclear obligations, see Note 16 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.

 
  Coal*
  Nuclear
  Natural Gas
   
NSP System
Generating Plants

  Average Fuel
Cost

  Cost
  Percent
  Cost
  Percent
  Cost
  Percent
  2007   $ 1.56   57 % $ 0.51   38 % $ 7.60   4 % $ 1.47
  2006     1.12   59     0.46   38     7.28   3     1.08
  2005     1.04   60     0.46   36     8.32   3     1.11

*
Includes refuse-derived fuel and wood

Fuel Sources  The NSP System normally maintains approximately 30 days of coal inventory at each plant site. Coal inventory levels, however, may vary widely among plants. Coal supply inventories at Dec. 31, 2007, were approximately 47 days usage, based on the maximum burn rate for all of NSP-Minnesota's coal-fired plants. NSP-Minnesota's generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana. 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 contracted for coal supplies to provide approximately 100 percent of its coal requirements in 2008, 63 percent of its coal requirements in 2009 and 39 percent of its coal requirements in 2010. Any remaining requirements will be filled through a request for proposal (RFP) process according to the fuel supply operations procurement strategy.

18


NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of approximately 100 percent of 2008, 2009 and 2010 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 with a focus on diversification to minimize potential impacts caused by supply interruptions that may be exacerbated by the supply/demand imbalance.

Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2008, approximately 63 percent of the requirements for 2009, 72 percent of the requirements for 2010 through 2012, 69 percent of the requirements for 2013 through 2015, 28 percent of the requirements for 2016 and 2017, with no coverage of requirements for 2018 and beyond. Contracts with additional uranium concentrate suppliers are currently in various stages of negotiations that are expected to provide a portion of the remaining open requirements through 2019.

Current contracts for conversion services cover 100 percent of the requirements through 2011 and approximately 52 percent of the requirements from 2012 through 2015, with no coverage for 2016 and beyond.

Current enrichment services contracts cover 100 percent of 2008 and approximately 94 percent of 2009 requirements. Approximately 29 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. A contract for additional enrichment services is being negotiated to provide 100 percent coverage for 2009 through 2013.

The fuel fabrication contract for Monticello was extended during 2007 to cover one additional reload in 2011. 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. Request for proposals from the fuel fabrication vendors for additional supply for Monticello is planned for 2008 with contract negotiations to follow.

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 2019. 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 and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel. The NSP System presently has no long-term supply commitments. The transportation and storage contracts expire in various years from 2010 to 2028. 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, 2007, NSP-Minnesota's commitments related to these transportation and storage contracts were approximately $575 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.


Wholesale 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 reduce 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

Public Utility Regulation

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

19


and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing, 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. 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 include an FCA (wholesale) to 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.

Wisconsin Renewable Portfolio Standard  The Wisconsin legislature passed a Renewable Portfolio Standard (RPS) that requires 10 percent of electric sales statewide be supplied by renewable energy sources by the year 2015. However, under the RPS, each individual utility must increase its renewable percentage by 6 percent over its baseline level. For NSP-Wisconsin the RPS is 12.85 percent since its baseline percentage was 6.85 percent. NSP-Wisconsin anticipates it will meet the RPS requirements with its pro-rata share of existing and planned renewable generation on the NSP System. Costs associated with complying with the standard are recoverable through general rate cases and the fuel cost recovery mechanism described above.


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

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction  PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale and the transmission of electricity in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices, however, as discussed previously, PSCo withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

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

ECA — Effective Jan. 1, 2007 the ECA includes an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism is revised

20


    quarterly and interest accrues monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

PCCA — The PCCA allows for recovery of purchased capacity payments to 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 are 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 RES 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.

Transmission Cost Adjustment (TCA) — Effective January 2008, the TCA provides for the recovery outside of rate cases of transmission plant revenue requirements and allows for a return on construction work in progress for investments for grid reliability or for new or upgraded transmission facilities.

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 2008, assuming normal weather, are listed below.

 
  System Peak Demand (in MW)
 
  2005
  2006
  2007
  2008 Forecast
PSCo   6,975   6,757   6,950   6,877

The peak demand for PSCo's system typically occurs in the summer. The 2007 system peak demand for PSCo occurred on July 24, 2007.

21




Energy Sources and Related Transmission Initiatives

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

Purchased Transmission Services  In addition to using its own transmission system, PSCo has 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.

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

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

PSCo Resource Plan  PSCo estimates it will purchase approximately 40 percent of its total electric system energy needs for 2008 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 2008 load obligation. In November 2007, PSCo filed the Colorado Resource Plan (CRP), which details the type and amount of resources that will be added to the system for an eight year Resource Acquisition Period (RAP) through 2015. Based on the plan, PSCo would:

Increase wind power resources by 800 MW by 2015. PSCo would then have a total of approximately 1,900 MW of wind power resources.

Acquire approximately 25 MW from a central solar facility, with plans to bring in a plant of up to 200 MW as technology develops.

Pursue an additional 29 MW of on-site, customer-owned solar installations.

Increase customer efficiency and conservation programs with plans to double the current capacity of its programs to 694 MW, while tripling the amount of annual energy sales reductions to approximately 2,350 GWh, by 2020.

Retire two older coal-burning plants (Arapahoe and Cameo) and repower at the Arapahoe site with a 480 MW summer rated combined cycle plant.

Also in November 2007, PSCo terminated a purchased power agreement, purchased the assets of the Squirrel Creek LLC project and filed a Certificate of Public Convenience and Necessity application with the CPUC to use the combustion turbines to build a new, company owned project at the existing Ft. St. Vrain generating station. This facility would come on line in 2009. If approved by the CPUC, the Fort St. Vrain project will leave PSCo 119 MW short of the necessary peaking power and 16 percent short of reserve margin necessary to meet the 2009 summer peak load. PSCo will meet the differential for the summer 2009 peak by purchasing short-term capacity. PSCo is requesting CPUC approval of the Fort St. Vrain application by April 2008.

Construction continues on a plant approved in the last resource planning docket (2003) of a 750 MW pulverized coal-fired unit at the existing Comanche power station located near Pueblo, Colo. and installation of additional emission control equipment on the two existing Comanche station units.

PSCo began construction of the new facility in the fall of 2005. Completion is planned for the fall of 2009. As part of an electric rate case, PSCo is allowed to include construction work in progress associated with the Comanche 3 project in rate base without an offset for allowance for funds used during construction, depending upon PSCo's senior unsecured debt rating.

PSCo has an agreement with Intermountain Rural Electric Association (IREA) and Holy Cross which transfers a portion of capacity ownership in the Comanche 3 unit to IREA and Holy Cross.

22


Renewable Energy Standard  The 2007 Colorado legislature adopted an increased RES that requires PSCo to generate or cause to be generated electricity from renewable resources equaling:

At least 10 percent of its retail sales by 2010,

15 percent of retail sales by 2015 and

20 percent of retail sales by 2020.

The new law limits the incremental retail rate impact from these acquisitions to 2 percent. The new legislation encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a rider mechanism and a return on construction work in progress.

Colorado Climate Action Plan  In November 2007, Governor Ritter of Colorado published a Colorado Climate Action Plan, which calls for a reduction in GHG emissions of 20 percent by 2020 with additional reductions by 2050.

RESA  In March 2006, the CPUC approved a RESA rider of 0.6 percent. 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. In response to the new RES, PSCo filed in late 2007 to increase the RESA to a full 2 percent in order to increase renewables to levels that comply with the 20 percent renewable energy requirement.

TCR Legislation  In 2007, a law was passed in Colorado which provides for rate rider recovery of all costs a utility incurs in the planning, development and construction or expansion of transmission facilities and for current recovery through this rider of the utility's weighted average cost of capital on transmission construction work in progress as of the end of the prior year. This legislation also provides for rate-regulated Colorado utilities to develop plans to construct or expand transmission facilities to transmission constrained zones where new electric generation facilities, including renewable energy facilities, are likely to be located and provides for expedited approvals for such facilities.

In October 2007, PSCo filed an application under the new legislation for a Certificate of Public Convenience and Necessity to construct a 345 KV transmission line from Pawnee Substation to its Smoky Hill Substation. The proposed new transmission line is intended to allow for injection of new generation capacity at Pawnee Substation for delivery to PSCo's load center located on the front range. PSCo estimates the cost of the new line to be approximately $110 million over five years.


Fuel Supply and Costs

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

 
  Coal
  Natural Gas
   
 
  Average Fuel
Cost

 
  Cost
  Percent
  Cost
  Percent
2007   $ 1.26   84 % $ 4.34   16 % $ 1.76
2006     1.24   85     6.52   15     2.01
2005     1.01   85     7.56   15     2.00

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  PSCo normally maintains approximately 30 days of coal inventory at each plant site. Coal inventory levels, however, may vary widely among plants. Coal supply inventories at Dec. 31, 2007, were approximately 41 days usage, based on the maximum burn rate for all of PSCo's coal-fired plants. PSCo's generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2007, PSCo's coal requirements for existing plants were approximately 10 million tons.

PSCo has contracted for coal suppliers to supply approximately 100 percent of its coal requirements in 2008, 76 percent of its coal requirements in 2009 and 30 percent of its coal requirements in 2010. Any remaining requirements will be filled through an RFP process according to the fuel supply operations procurement strategy.

PSCo has coal transportation contracts that provide for delivery for approximately 100 percent of 2008 coal requirements, 35 percent of 2009 coal requirements and 33 percent of 2010 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

23


PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for associated transportation and storage services for PSCo's power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply contracts expire in various years from 2008 to 2010. The transportation and storage contracts expire in various years from 2009 to 2040. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2007, PSCo's commitments related to supply contracts were approximately $161 million and transportation and storage contracts were approximately $1.0 billion.


Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. PSCo uses physical and financial instruments to 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

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction  The PUCT and NMPRC regulate SPS' retail electric operations 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. SPS is participating in a PUCT rulemaking project to amend the PUCT's regulations to provide for more frequent timely changes in fixed fuel factors.

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.

Performance-Based Regulation and Quality of Service Requirements  In Texas, SPS is subject to a quality of service plan requiring SPS to comply with electric service reliability performance targets. If these targets are not met, the PUCT staff may initiate proceedings for an investigation and possible imposition of an administrative penalty.

Texas Energy Legislation  The 2005 Texas legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the ERCOT in the SPP or the WECC to have timely recovery from Texas retail consumers of utility transmission infrastructure investments. In December 2007, the PUCT adopted regulations that allow such utilities, including SPS, to seek approval of a TCR factor for 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.

24


Texas Renewable Energy Zones  In 2007, the PUCT designated competitive renewable energy zones (CREZs), which are regions of the state which are sufficient to develop renewable energy generation sources, such as wind. Several CREZ areas within the SPS service region were designated for potential development. A statewide study conducted by the ERCOT identifies the Texas panhandle as having the top four of the state's primary areas for wind energy expansion. Several transmission proposals have been filed in the CREZ proceeding, including plans to interconnect CREZs with the SPP and plans that would collect wind energy from panhandle CREZs and deliver it into ERCOT.

Texas Goal for Renewable Energy  The Texas legislature and the PUCT have adopted renewable portfolio standards that require the development of renewable resources by 2007 and increasing requirements through 2025. SPS has already solicited for renewable energy resources and they have been developed in the SPS area and are providing renewable energy sufficient to meet the Texas renewable energy requirements.

John Deere Wind Complaint — On June 27, 2007, several of the John Deere wind subsidiaries (JD Wind) filed a complaint against SPS disputing SPS' payments to JD Wind for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind for energy produced from its QF is appropriate and in accordance with SPS' filed tariffs with the PUCT. The PUCT has referred the complaint to the State Office of Administrative Hearings.

New Mexico Renewable Portfolio Standard  The 2007 New Mexico legislature enacted a renewable portfolio standard in which renewable energy must comprise no less than 5 percent of retail sales by 2006; 10 percent by 2011; 15 percent by 2015; and 20 percent by 2020. The legislation also allows incentives to encourage the acquisition of renewable energy supplies beyond the requirements. The NMPRC has implemented revised rules related to the increased requirements. The NMPRC has interpreted the diversification requirement to mean no less than 20 percent of the standard is met using wind energy, no less than 20 percent using central solar, no less than 10 percent other (e.g., biomass, geothermal), and no less than 1.5 percent using renewable distributed generation (increasing to 3 percent by 2015). The effective date of the diversification requirements is 2011.


Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2008, assuming normal weather, are listed below.

 
  System Peak Demand (in MW)
 
  2005
  2006
  2007
  2008 Forecast
SPS   4,660   4,711   4,731   4,908

The peak demand for the SPS system typically occurs in the summer. The 2007 system peak demand for SPS occurred on Aug. 20, 2007.


Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases and DSM options to meet its net dependable system capacity requirements.

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

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

Lea Power Partners — Lea Power is a natural gas combined cycle 602 MW plant currently being constructed near Hobbs, New Mexico. SPS is expected to begin to take energy beginning June 2008 when Lea Power reaches commercial operations. The purchase power agreement, which was executed in 2006, provides for SPS to have exclusive rights to dispatch the facility.

25


Integrated Resource Planning — In accordance with a final rule adopted by the NMPRC, SPS is required to file an integrated resource plan (IRP) with the NMPRC on or before July 2009. Also as part of this requirement, SPS must initiate a public advisory process on or before July 2008.

Acquisition of Renewable Resources — In accordance with a final rule adopted by the NMPRC, SPS must require certain quantities and specific types of renewable resources on or before 2011. To meet this requirement, SPS plans to submit an RFP during the first quarter of 2008. See discussion above on New Mexico Renewable Portfolio Standard.

Purchased Transmission Services  SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its 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 systems are through FERC approved 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

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

 
  Coal
  Natural Gas
   
SPS Generating Plants

  Average Fuel
Cost

  Cost
  Percent
  Cost
  Percent
2007   $ 1.64   67 % $ 6.45   33 % $ 3.22
2006     1.89   66     6.30   34     3.38
2005     1.32   68     7.77   32     3.38

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 (TUCO). 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.

As of Dec. 31, 2007, coal supplies at the Harrington and Tolk sites were approximately 34 and 31 days supply, respectively.

TUCO has coal agreements to supply 100 percent of SPS' coal requirements in 2008 and 2009, and 82 percent of the 2010 coal requirements, which are 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 supplies and associated transportation and storage services for SPS' power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply contracts expire in various years from 2008 through 2010. The transportation and storage contracts expire in various years from 2008 to 2033. 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, 2007, SPS' commitments related to supply contracts were approximately $31 million and transportation and storage contracts were approximately $254 million.

26




Wholesale 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,
 
 
  2007
  2006
  2005
 
Electric Sales (Millions of Kwh)                    
Residential     24,866     24,153     23,930  
Commercial and Industrial     62,396     61,314     60,049  
Public Authorities and Other     1,087     1,118     1,091  
   
 
 
 
Total Retail     88,349     86,585     85,070  
Sales for Resale     24,202     23,960     22,194  
   
 
 
 
Total Energy Sold     112,551     110,545     107,264  
   
 
 
 
Number of Customers at End of Period                    
Residential     2,859,262     2,831,704     2,791,859  
Commercial and Industrial     408,366     403,678     400,035  
Public Authorities and Other     71,726     73,279     75,937  
   
 
 
 
Total Retail     3,339,354     3,308,661     3,267,831  
Wholesale     129     138     128  
   
 
 
 
Total Customers     3,339,483     3,308,799     3,267,959  
   
 
 
 
Electric Revenues (Thousands of Dollars)                    
Residential   $ 2,281,354   $ 2,149,978   $ 2,048,100  
Commercial and Industrial     4,099,017     4,014,809     3,733,648  
Public Authorities and Other     118,024     118,660     110,895  
   
 
 
 
Total Retail     6,498,395     6,283,447     5,892,643  
Wholesale     1,180,728     1,141,248     1,193,762  
Other Electric Revenues     168,869     183,323     157,232  
   
 
 
 
Total Electric Revenues   $ 7,847,992   $ 7,608,018   $ 7,243,637  
   
 
 
 
Kwh Sales per Retail Customer     26,457     26,169     26,033  
Revenue per Retail Customer   $ 1,946.00   $ 1,899.09   $ 1,803.23  
Residential Revenue per Kwh     9.17 ¢   8.90 ¢   8.56 ¢
Commercial and Industrial Revenue per Kwh     6.57     6.55     6.22  
Wholesale Revenue per Kwh     4.88     4.76     5.38  

27



NATURAL GAS UTILITY OPERATIONS

Natural Gas Utility Trends

The most significant recent developments in the natural gas operations of the utility subsidiaries are 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 1997 to 2007, average annual sales to the typical residential customer declined from 102 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

Public Utility Regulation

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. While this law will change to a savings-based requirement beginning in 2010 pursuant to 2007 legislation, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.


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 643,320 MMBtu for 2007, which occurred on Feb. 7, 2007.

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 562,298 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 36 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 33 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 and 2007-2008 entitlement levels are pending MPUC action.

28




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:

2007   $ 7.67
2006     8.32
2005     8.90

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 2008 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, 2007, NSP-Minnesota was committed to approximately $813 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

Public Utility Regulation

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 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 173,617 MMBtu for 2007, which occurred on Feb. 4, 2007.

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 129,511 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 26 percent of winter natural gas requirements and 40 percent of peak day, firm requirements of NSP-Wisconsin.

29


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 13 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 2007-2008 supply plan was approved by the PSCW in November 2007.


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:

2007   $ 7.56
2006     8.42
2005     8.64

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 2008 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, 2007, NSP-Wisconsin was committed to approximately $80 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

Public Utility Regulation

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

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

GCA — The GCA mechanism allows PSCo to recover its actual costs of purchased gas, 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.

30




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 1,864,044 MMBtu. In addition, firm transportation customers hold 591,140 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,455,184 MMBtu per day. The maximum daily deliveries for PSCo in 2007 for firm and interruptible services were 1,798,030 MMBtu on Jan. 12, 2007.

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 1,612,234 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 35,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo's city gate meter stations and a small amount is received directly from wellhead sources.

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 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:

2007   $ 5.87
2006     7.09
2005     8.01

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, 2007, PSCo was committed to approximately $1.9 billion in such obligations under these contracts, which expire in various years from 2008 through 2028.

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 2007, PSCo purchased natural gas from approximately 40 suppliers.

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

31




Xcel Energy Gas Operating Statistics

 
  Year Ended Dec. 31,
 
  2007
  2006
  2005
Gas Deliveries (Thousands of MMBtu)                  
Residential     138,198     126,846     135,794
Commercial and Industrial     88,668     81,107     83,667
   
 
 
  Total Retail     226,866     207,953     219,461
Transportation and Other     133,851     135,708     134,061
   
 
 
  Total Deliveries     360,717     343,661     353,522
   
 
 
Number of Customers at End of Period                  
Residential     1,688,994     1,669,747     1,636,652
Commercial and Industrial     149,557     147,614     145,067
   
 
 
  Total Retail     1,838,551     1,817,361     1,781,719
Transportation and Other     4,146     3,981     3,764
   
 
 
  Total Customers     1,842,697     1,821,342     1,785,483
   
 
 
Gas Revenues (Thousands of Dollars)                  
Residential   $ 1,295,095   $ 1,330,025   $ 1,450,316
Commercial and Industrial     738,035     755,204     794,230
   
 
 
  Total Retail     2,033,130     2,085,229     2,244,546
Transportation and Other     78,602     70,770     62,839
   
 
 
  Total Gas Revenues   $ 2,111,732   $ 2,155,999   $ 2,307,385
   
 
 
MMBtu Sales per Retail Customer     123.39     114.43     123.17
Revenue per Retail Customer   $ 1,105.83   $ 1,147.39   $ 1,259.76
Residential Revenue per MMBtu     9.37     10.49     10.68
Commercial and Industrial Revenue per MMBtu     8.32     9.31     9.49
Transportation and Other Revenue per MMBtu     0.59     0.52     0.47


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 15 and 16 to the consolidated financial statements, environmental matters in Management's Discussion and Analysis under Item 7 and the matters discussed below.

Leyden Natural Gas Storage Facility (Leyden) — In February 2001, the CPUC approved PSCo's plan to abandon 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. The final report of post closure monitoring will be filed with the Colorado Oil and Gas Conservation Commission in early 2008. As of Dec. 31, 2005, PSCo had incurred approximately $5.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo accrued an additional $0.2 million of costs through 2006 to complete the decommissioning and closure of the facility. In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional Leyden costs, plus unrecovered amounts authorized from a previous rate case, which amounted to $5.9 million to be amortized over four years. The total amount PSCo requested to be recovered from customers was $7.7 million. Xcel Energy reached a settlement agreement with the parties in the 2006 rate case accepting the PSCo recovery amounts. The CPUC approved the settlement agreement in June 2007.

32




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, 2007, is presented in the table below. Of the full-time employees listed below, 5,663, or 52 percent, are covered under collective bargaining agreements. See Note 10 in the consolidated financial statements for further discussion of the bargaining agreements.

NSP-Minnesota   3,561
NSP-Wisconsin   543
PSCo   2,734
SPS   1,145
Xcel Energy Services Inc   2,934
   
Total   10,917
   


EXECUTIVE OFFICERS

Richard C. Kelly, 61, 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, 56, 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.

Michael C. Connelly, 46, Vice President and General Counsel, Xcel Energy Inc., June 2007 to present. Previously, Vice President of Human Resources November 2005 to June 2007; Vice President and Deputy General Counsel January 2003 to November 2005; Deputy General Counsel August 2000 to January 2003.

David L. Eves 49, 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.

Benjamin G.S. Fowke III, 49, 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.

Raymond E. Gogel, 57, Vice President, Xcel Energy Services Inc., April 2002 to present; Vice President Customer and Enterprise Solutions 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, 58, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, November 2005 to present.

Cynthia L. Lesher, 59, 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, 51, 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.

33


David M. Sparby, 53, 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.

Michael L. Swenson, 57, President, Director 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.

Tim E. Taylor, 60, President, Director and Chief Executive Officer, Public Service Company of Colorado, September 2007 to present. Previously, Vice President of Asset Management — Utilities Group, Xcel Energy, Inc., February 2006 to September 2007; Vice President, Field Operations, January 2004 to February 2006 and Vice President, Asset Management, May 2002 to January 2004.

George E. Tyson II, 42, 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.

David M. Wilks, 61, Vice President, Xcel Energy Services Inc., September 2000 to present; President — Energy Supply Group, Xcel Energy Inc., August 2000 to present.

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

34



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 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 the costs of 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. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. 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 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.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including 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 purchase 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 purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

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

We are subject to capital market risk.

Utility operations require significant capital investment in plant, property and equipment; consequently, Xcel Energy is an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage

35



market, could prevent Xcel Energy from issuing new securities or cause us to issue securities with less than ideal terms and conditions.

We are subject to credit risks.

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

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

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

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

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2007, these included:

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.

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

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

36


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

There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. Xcel Energy does not serve any coastal communities so the possibility of sea level rises does not directly affect Xcel Energy or its customers. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of the company's service territory could also have an impact on Xcel Energy revenues. Xcel Energy buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts Xcel Energy service territories, primarily through thunderstorms, tornadoes and snow or ice storms. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

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

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

Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Xcel Energy's electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. Xcel Energy is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with the our environmental leadership strategy.

Many of the federal and state climate change legislative proposals use a "cap and trade" policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain "allowances" or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a "cap and trade" structure, on Xcel Energy and its customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. An important factor is Xcel Energy's ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on Xcel Energy or its operating subsidiaries. If our regulators do not allow us to recover all or a part of the cost of capital

37



investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion see the Management's Discussion and Analysis section and Note 15 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, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.

Worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.

Our utility operations are subject to long term planning risks.

On a periodic basis, or as needed, our utility operations file long term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production and customer response. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.

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

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

38



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

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results. It's difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.

Rising energy prices could negatively impact our business.

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

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

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

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

39


Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC's civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. Effective June 2007, 83 electric reliability standards that were historically subject to voluntary compliance could negativity impact our business became 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 and related contributions may change in the future.

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

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


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.

40



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 2007 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   1987-2002   298  
High Bridge-St. Paul, MN              
  2 Units   Coal   1956-1959   271 (b)
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.

(b)
High Bridge coal units were removed from service on Aug. 31, 2007.


NSP-Wisconsin

Station, City and Unit

  Fuel
  Installed
  Summer 2007 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   1948-1956   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.

41



PSCo

Station, City and Unit

  Fuel
  Installed
  Summer 2007 Net
Dependable
Capability (MW)

 
Steam:              
  Arapahoe-Denver, CO 2 Units   Coal   1951-1955   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 2007 Net
Dependable
Capability (MW)

Steam:            
  Harrington-Amarillo, TX 3 Units   Coal   1976-1980   1,041
  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   4,290
           

42


Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2007:

Conductor Miles

  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  SPS
500 KV   2,917      
345 KV   5,564   1,312   957   5,139
230 KV   1,801     11,393   9,420
161 KV   295   1,495    
138 KV       92  
115 KV   6,577   1,529   4,871   10,878
Less than 115 KV   82,100   31,807   72,027   22,724

Electric utility transmission and distribution substations at Dec. 31, 2007:

 
  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  SPS
Quantity   367   203   216   432

Gas utility mains at Dec. 31, 2007:

Miles

  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  WGI
Transmission   135     2,306   12
Distribution   9,446   2,172   20,815  


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.


Additional Information

For a discussion of legal claims and environmental proceedings, see Note 15 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 14 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 2007.

43



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 2007 and 2006 and the dividends declared per share during those quarters.

 
  High
  Low
  Dividends
2007                  
First Quarter   $ 24.94   $ 22.75   $ 0.2225
Second Quarter     25.03     19.97     0.2300
Third Quarter     22.41     19.59     0.2300
Fourth Quarter     23.50     20.70     0.2300

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

Book value per share at Dec. 31, 2007, was $14.70. The number of common shareholders of record as of Dec. 31, 2007 was 91,000. Xcel Energy's Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock.

At Dec. 31, 2007 and 2006, 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 Investor-Owned Electrics Index over the last five fiscal years (assuming a $100 investment in each vehicle on Dec. 31, 2002, and the reinvestment of all dividends).

The EEI Investor-Owned Electrics Index currently includes 61 companies and is a broad measure of industry performance.


COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Xcel Energy, The S&P 500
and The EEI Investor-Owned Electrics

GRAPHIC


*
$100 invested on 12/31/02 in stock or index — including reinvestment of dividends. Fiscal years ending December 31.

 
  2002
  2003
  2004
  2005
  2006
  2007
Xcel Energy   $ 100   $ 162   $ 181   $ 193   $ 252   $ 256
S&P 500     100     129     143     150     173     183
EEI Investor-Owned Electrics     100     123     152     176     213     248

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

44



Item 6 — Selected Financial Data

 
  2007
  2006
  2005
  2004
  2003
 
 
  (Millions of Dollars, Except Share and Per-Share Data)
 
Operating revenues   $ 10,034   $ 9,840   $ 9,625   $ 8,216   $ 7,731  
Operating expenses     8,683     8,663     8,533     7,140     6,607  
Income from continuing operations     576     569     499     522     523  
Net income     577     572     513     356     622  
Earnings available for common stock     573     568     509     352     618  
Average number of common shares outstanding (000's)     416,139     405,689     402,330     399,456     398,765  
Average number of common and potentially dilutive shares outstanding (000's)     433,131     429,605     425,671     423,334     418,912  
Earnings per share from continuing operations — basic   $ 1.38   $ 1.39   $ 1.23   $ 1.30   $ 1.30  
Earnings per share from continuing operations — diluted     1.35     1.35     1.20     1.26     1.26  
Earnings per share — basic     1.38     1.40     1.26     0.88     1.55  
Earnings per share — diluted     1.35     1.36     1.23     0.87     1.50  
Dividends declared per share     0.91     0.88     0.85     0.81     0.75  
Total assets     23,185     21,958     21,505     20,305     20,205  
Long-term debt(b)     6,342     6,450     5,898     6,493     6,494  
Book value per share     14.70     14.28     13.37     12.99     12.95  
Return on average common equity     9.5 %   10.1 %   9.6 %   6.8 %   12.6 %
Ratio of earnings to fixed charges(a)     2.2     2.2     2.1     2.2     2.2  

(a)
Excludes undistributed equity income and includes allowance for funds used during construction.
(b)
Long-term debt includes only debt of continuing operations.

45



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 2007, 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 credits.


Discontinued Operations

See Note 3 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 or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under 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, 2007 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2007.


Management's Strategic Plan

Xcel Energy's strategy, called Building the Core, has three primary focuses: environmental leadership, achieving financial objectives and optimizing the management of a portfolios of operating utilities. In summary, our objective is to embrace growing customer demand and environmental initiatives by investing in our core utility businesses and earning a reasonable return on our invested capital. Below is a detailed discussion of our three primary focuses and how they support our overall Building the Core strategy.

Xcel Energy's Environmental Leadership

Xcel Energy has adopted environmental leadership as a primary focus, forming the cornerstone of all our strategic initiatives. Xcel Energy believes that our environmental leadership meets customer and policy maker expectations and, in turn, creates significant shareholder value.

As a portfolio of regulated utilities, Xcel Energy has an obligation to serve its customers by providing them with reasonably priced, reliable electric and gas services. However, Xcel Energy's strategy goes beyond this traditional mission. Under the environmental leadership strategy, Xcel Energy assesses and takes prudent, balanced steps to reduce the impact of our operations on the environment while promoting technological and public policy advancements that will encourage a cleaner electric system. In light of the capital-intensive nature of our business, including the long life of

46



Xcel Energy's capital investments, Xcel Energy assesses and takes prudent steps to reduce the overall risk associated with potential new environmental mandates. Finally, Xcel Energy seeks to reduce regulatory uncertainty through favorable cost recovery for environmental initiatives provided by public policy makers, including legislatures and public utilities commissions.

The foundation for Xcel Energy's environmental leadership strategy resides with its environmental policy. Under this policy, the Xcel Energy Board of Directors, acting through the Nuclear, Environmental and Safety Committee, oversees Xcel Energy's environmental compliance program and policy initiatives. The policy is available on our website at www.xcelenergy.com. Xcel Energy has created an environmental management system that provides employees with training and documentation of Xcel Energy's compliance responsibilities, creates processes designed to minimize the risk of noncompliance and audits Xcel Energy's environmental performance. Environmental performance is incorporated into officer and employee job responsibilities and compensation.

Xcel Energy pursues environmental leadership through management of environmental policy initiatives. Xcel Energy actively evaluates public policy proposals and promotes environmental initiatives that are designed to create shareholder value, reduce financial risk and provide growth opportunities. These initiatives include the following:

Xcel Energy has implemented voluntary emission reduction programs in Minnesota and Colorado. These programs have resulted or will result in substantial emission reductions from existing facilities. They also incorporate enhanced cost recovery mechanisms that provide shareholders with favorable returns for the associated emission reduction investments.

Xcel Energy is the nation's largest utility wind energy provider. Xcel Energy is pursuing new wind, solar and other renewable energy acquisitions and investments to meet some of the nation's most aggressive renewable energy standards in the states in which Xcel Energy operates. Xcel Energy has worked with state policy makers to design these standards to incorporate favorable cost recovery mechanisms and investment opportunities.

Xcel Energy is a leader in promoting new, clean energy technologies. Xcel Energy has undertaken small-scale projects to study the technical and economic aspects of energy storage and the use of hydrogen. Xcel Energy is a leader in supporting the advancement of solar energy technology. Xcel Energy is also exploring the use of clean coal and is evaluating whether and how to best take advantage of state and federal incentives for clean coal development.

Xcel Energy has a number of environmental initiatives focused on our customers. In Colorado, Xcel Energy has the largest customer-driven wind program in the nation (WindSource) and a growing customer-sited solar program, known as "Solar*Rewards." Xcel Energy also has an increasing portfolio of customer energy efficiency and conservation programs and is working with state commissions to enhance the financial incentives associated with our programs. Xcel Energy is also working to apply intelligence to its electric grid (creating a "SmartGrid") to provide customers with more choice, reliability and control over their energy use.

While Xcel Energy is not currently subject to state or federal regulation of its GHG emissions, as one of the nation's largest electric generating companies, Xcel Energy is committed to addressing climate change through efforts to reduce its GHG emissions. Xcel Energy's current electric generating portfolio includes coal- and gas-fired plants that are projected to emit approximately 67 million tons of CO2 in 2007. Purchased generation is expected to emit approximately 18 million tons of CO2 in 2007. There has been a combined cumulative reduction of over 18.5 million tons of CO2 since 2003. Xcel Energy is implementing aggressive future resource development and conservation plans that will further reduce the company's CO2 emissions, both in absolute terms and per Kwh of electricity produced. See Management's Discussion and Analysis for further discussion.

In 2007, Xcel Energy filed resource plans in Minnesota and Colorado that propose significant new clean energy resources. If the state commissions approve these plans, Xcel Energy would:

Increase overall system wind capacity from approximately 2,800 MW by the end of 2007 to approximately 6,000 MW by 2020;

Add 225 MW of concentrating solar thermal technology;

Reduce retail demand through energy efficiency and conservation programs by 1.1 percent in Minnesota and 0.7 percent in Colorado;

Retire and replace approximately 230 MW of coal-fired electric generation;

47


Improve the efficiency of and reduce CO2, mercury, SO2 and NOx emissions at several existing fossil plants; and

Upgrade the efficiency and capacity of existing nuclear facilities.

Xcel Energy has designed these plans so that, depending on fuel, commodity and other assumptions, Xcel Energy would maintain a reasonably priced product and continue to provide reliable power to our customers. At the same time, if approved, the plans would result in a significant reduction in CO2 emissions. The proposed Minnesota plan would reduce NSP-Minnesota's CO2 emissions by 22 percent below 2005 levels by 2020. The proposed Colorado plan would reduce PSCo's CO2 emissions by 10 percent below 2005 levels by 2017 and position PSCo to propose additional reductions to achieve a 20 percent reduction by 2020.

Our environmental leadership strategy has resulted in numerous environmental awards and recognition. For example, Xcel Energy was named to the Dow Jones Sustainability Index for North America for 2007-2008, the second consecutive year that Xcel Energy has earned this distinction. Xcel Energy strives to provide the public with detailed information regarding environmental performance and risk. Among other things, our utility companies operating in Minnesota, Colorado, and New Mexico use a carbon proxy cost mandated by the state commissions to evaluate the impact of potential future CO2 regulation on its future resource acquisition plans. Xcel Energy publishes a Triple Bottom Line Report annually, which is available on our website, www.xcelenergy.com. The Triple Bottom Line report discloses Xcel Energy's environmental, economic and social performance. Xcel Energy also provides detailed information to environmental research organizations, such as Trucost, the Carbon Disclosure Project and the Climate Registry.

Achieving Financial Objectives

Xcel Energy's financial objectives of Building the Core also has three phases: obtaining legislative and regulatory support for large investment initiatives, investing in the utility business and earning a fair return on utility system investments.

The first phase, as noted above, is obtaining legislative and regulatory support for large investment initiatives, prior to making the investment. To avoid excessive risk to Xcel Energy, it is critical that Xcel Energy reduce regulatory uncertainty before making large capital investments. Xcel Energy has accomplished this for both the MERP in Minnesota and the Comanche 3 coal unit in Colorado. Transmission legislation has been passed in Minnesota, Colorado, Texas and several other jurisdictions where Xcel Energy operates.

The second phase is investing in the utility business. In addition to Xcel Energy's normal level of capital investment, Xcel Energy expects to have significant investment opportunity, in part attributable to the environmental strategy described above. Those opportunities include the following:

Approximately $1 billion through 2010 for MERP, a project to convert an aging coal-fired plant to a natural gas plant and to install pollution control at another plant. During 2007, the initial phase of this project was completed with the successful conversion of the Allen S. King plant to a natural gas facility;

Approximately $1 billion through 2010 for Comanche 3, a project to build an additional coal unit in Colorado;

Approximately $215 million for the planned addition of two gas fired units totaling 300 MW at the Fort St. Vrain generating facility located in Colorado;

A proposed $1 billion investment through 2015 to extend the lives and increase the output of two nuclear facilities, Monticello and Prairie Island;

A proposed $1.1 billion investment through 2015 to add capacity and reduce emissions at the Sherco coal fired plant;

A planned investment by the CapX 2020 coalition of utilities ranging from $1.3 billion to 1.6 billion between 2008 and 2015 to expand the transmission system in the upper Midwest, of which Xcel Energy's share of the investment would be approximately $700 million, representing the first phase of CapX 2020; and

Several other potential environmental initiatives, including substantial wind generation investment described above and outlined in the recently proposed Colorado and Minnesota resource plans.

As a result of these investments, as well as continued investments in the transmission and distribution system, Xcel Energy expects that the rate base, or the amount on which Xcel Energy earns a return, will grow on average annually by more than seven percent from 2006 through 2011.

48


The third phase is earning a fair return on utility system investments. To this end, the 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 of 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 Xcel Energy to earn a return on the project, while each of the facilities is being constructed.

Xcel Energy's regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility investments. Xcel Energy believes that the public utility commissions will provide reasonable recovery, and it is important to note that the financial plans include this assumption. Constructive results over the last several years are evidence of reasonable regulatory treatment and give Xcel Energy confidence that Xcel Energy is pursuing the right strategy. These rate cases, as well others planned for 2008 and beyond, are some of the building blocks of the earnings growth plan.

With any strategic plan, there are goals and objectives. Xcel Energy feels the following financial objectives continue to be 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 the Building the Core strategic plan should allow Xcel Energy to achieve the outlined financial objectives, which in turn should provide investors with an attractive total return on a low-risk investment.

Optimizing the Management of a Portfolio of Operating Utilities

Optimizing the management of a portfolio of operating utilities is the third area of focus related to the Building the Core strategy. Even though Xcel Energy ultimately manages the business based on the revenue streams provided by electric and natural gas, Xcel Energy continues to evolve the management of the portfolio of utility investments. While Xcel Energy has four separate operating companies, there are certain similarities and differences that require a new approach to more effectively manage this portfolio. More specifically, Xcel Energy's goal is to build on the similarities among the companies, which maximizes efficiencies from centralized management and deployment of common initiatives. Examples include market branding and environmental policy research. From an organizational perspective, examples include corporate center services as well as certain operational functions, such as asset management, environmental compliance and safety.

At the same time, Xcel Energy realizes there are unique differences in each of our service territories such as local community focus and priorities, regulatory environment, physical plant infrastructure and age, weather, as well as others that require Xcel Energy to organize / align these utility specific areas to most effectively address these utility distinct characteristics. To that end, Xcel Energy has operating presidents, each located in their respective jurisdiction. The objective of this organizational structure is to optimize Xcel Energy's operating efficiency while maximizing accountability.


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

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

49


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 Inc. (e prime), which were classified as held for sale in late 2003 based on the decision to divest them.

See Note 3 to the consolidated financial statements for a further discussion of discontinued operations.

 
  Contribution to earnings
 
 
  2007
  2006
  2005
 
 
  (Millions of Dollars)
 
GAAP income by segment                    
Regulated electric utility income — continuing operations   $ 554.7   $ 503.1   $ 440.6  
Regulated natural gas utility income — continuing operations     108.0     70.6     71.2  
Other regulated utility income(a)     (26.7 )   32.3     27.6  
   
 
 
 
  Total utility income — continuing operations     636.0     606.0     539.4  
Holding company costs and other results(a)     (60.1 )   (37.3 )   (40.3 )
   
 
 
 
  Total income — continuing operations     575.9     568.7     499.1  
Regulated utility income — discontinued operations         3.0     0.2  
Other nonregulated income — discontinued operations     1.4     0.1     13.7  
   
 
 
 
  Total income — discontinued operations     1.4     3.1     13.9  
   
 
 
 
    Total GAAP net income   $ 577.3   $ 571.8   $ 513.0  
   
 
 
 
 
 
  Contribution to earnings per share
 
 
  2007
  2006
  2005
 
GAAP earnings per share contribution by segment                    
Regulated electric utility — continuing operations   $ 1.28   $ 1.17   $ 1.04  
Regulated natural gas utility — continuing operations     0.25     0.16     0.17  
Other regulated utility(a)     (0.06 )   0.08     0.06  
   
 
 
 
  Total utility earnings per share — continuing operations     1.47     1.41     1.27  
Holding company costs and other results(a)     (0.12 )   (0.06 )   (0.07 )
   
 
 
 
  Total earnings per share — continuing operations     1.35     1.35     1.20  
Regulated utility earnings — discontinued operations         0.01      
Other nonregulated earnings — discontinued operations             0.03  
   
 
 
 
  Total earnings per share — discontinued operations         0.01     0.03  
   
 
 
 
    Total GAAP earnings per share — diluted   $ 1.35   $ 1.36   $ 1.23  
   
 
 
 

(a)
Not a reportable segment. Included in All Other segment results in Note 18 to the consolidated financial statements.

Earnings from continuing operations for 2007 were higher than in 2006. The increase in 2007 earnings were primarily attributed to higher electric and gas margins, reflecting various rate increases, weather-normalized retail sales growth, higher rider recovery, and the impact of favorable temperatures, which also increased sales. Partially offsetting these positive factors were higher operating and maintenance expense, increased interest expense and a higher effective tax rate.

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.

50


During 2007, Xcel Energy entered into a settlement agreement with the IRS related to a dispute associated with its COLI program. Excluding this settlement, along with the earnings associated with this insurance program, Xcel Energy's ongoing 2007 earnings were $612 million, or $1.43 per share, compared with 2006 ongoing earnings of $548 million or $1.30 per share. The following table provides a reconciliation of GAAP earnings and earnings per share to ongoing earnings and earnings per share for 2007, 2006 and 2005.

 
  2007
  2006
  2005
 
  (Millions of Dollars)
Ongoing earnings   $ 612.0   $ 548.2   $ 480.4
PSRI earnings     23.4     20.5     18.7
Interest, penalties and tax related to IRS COLI settlement     (59.5 )      
   
 
 
  Total continuing operations     575.9     568.7     499.1
   
 
 
Discontinued operations     1.4     3.1     13.9
   
 
 
    Total GAAP earnings   $ 577.3   $ 571.8   $ 513.0
   
 
 
 
  2007
  2006
  2005
Ongoing earnings per share   $ 1.43   $ 1.30   $ 1.15
PSRI earnings     0.05     0.05     0.05
Interest, penalties and tax related to IRS COLI settlement     (0.13 )      
   
 
 
  Earnings per share — continuing operations     1.35     1.35     1.20
Discontinued operations         0.01     0.03
   
 
 
    Total GAAP earnings per share   $ 1.35   $ 1.36   $ 1.23
   
 
 

As a result of the termination of the COLI program, Xcel Energy's management believes that ongoing earnings provide a more meaningful comparison of earnings results between different periods in which the COLI program was in place and is more representative of Xcel Energy's fundamental core earnings power. Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation and when communicating its earnings outlook to analysts and investors.

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.

 
  Contribution to earnings
 
 
  2007
  2006
  2005
 
Earnings Contribution by Company              
NSP-Minnesota   45.9 % 47.4 % 46.6 %
PSCo   51.0   41.5   41.7  
SPS   5.7   8.1   12.5  
NSP-Wisconsin   6.5   7.4   5.0  
   
 
 
 
  Total regulated utility contribution   109.1   104.4   105.8  
Holding company and other subsidiaries   (9.1 ) (4.4 ) (5.8 )
   
 
 
 
  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 2007 increased earnings by an estimated 6 cents per share;

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

Weather in 2005 decreased earnings by an estimated 3 cents per share.

51



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 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)
 
2007                          
Electric utility revenues (excluding commodity trading)   $ 7,611   $ 227   $   $ 7,838  
Electric fuel and purchased power-utility     (3,930 )   (207 )       (4,137 )
Commodity trading revenues             289     289  
Commodity trading expenses             (279 )   (279 )
   
 
 
 
 
Gross margin before operating expenses   $ 3,681   $ 20   $ 10   $ 3,711  
   
 
 
 
 
Margin as a percentage of revenues     48.4 %   8.8 %   3.5 %   45.7 %
2006                          
Electric utility revenues (excluding commodity trading)   $ 7,387   $ 201   $   $ 7,588  
Electric fuel and purchased power-utility     (3,925 )   (178 )       (4,103 )
Commodity trading revenues             610     610  
Commodity trading expenses             (590 )   (590 )
   
 
 
 
 
Gross margin before operating expenses   $ 3,462   $ 23   $ 20   $ 3,505  
   
 
 
 
 
Margin as a percentage of revenues     46.9 %   11.4 %   3.3 %   42.8 %
2005                          
Electric utility revenues (excluding commodity trading)   $ 7,038   $ 196   $   $ 7,234  
Electric fuel and purchased power-utility     (3,802 )   (120 )       (3,922 )
Commodity trading revenues             730     730  
Commodity trading expenses             (720 )   (720 )
   
 
 
 
 
Gross margin before operating expenses   $ 3,236   $ 76   $ 10   $ 3,322  
   
 
 
 
 
Margin as a percentage of revenues     46.0 %   38.8 %   1.4 %   41.7 %
   
 
 
 
 

52


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

Base Electric Utility Revenues

 
  2007 vs. 2006
 
 
  (Millions of Dollars)
 
PSCo electric retail rate increase   $ 112  
Retail sales growth (excluding weather impact)     49  
Transmission revenues     32  
MERP rider     29  
Conservation and non-fuel riders (partially offset in O&M expense)     26  
Miscellaneous revenues (partially offset in O&M expense)     17  
Estimated impact of weather     16  
Firm wholesale     15  
Fuel and purchased power cost recovery     (66 )
Other     (6 )
   
 
  Total increase in base electric utility revenues   $ 224  
   
 

2007 Comparison with 2006 — Base electric utility revenues increased due to a PSCo electric retail rate increase, weather-normalized retail sales growth of approximately 1.7 percent, higher transmission revenues, higher recovery from the MERP rider, which recovers financing and other costs related the MERP construction projects and higher conservation and non-fuel rider recovery, mostly from the RESA and DSM riders at PSCo. Lower fuel and purchased power costs, largely recovered from customers, partially offset the positive variances.

 
  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 (partially offset in O&M expense)     24  
Quality of service obligations     12  
SPS Texas surcharge decision     (8 )
SPS FERC 206 rate refund accrual     (8 )
Other     15  
   
 
  Total increase in base electric utility revenues   $ 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.

Base Electric Utility Margin

 
  2007 vs. 2006
 
 
  (Millions of Dollars)
 
PSCo electric retail rate increase   $ 112  
Retail sales growth (excluding weather impact)     49  
MERP rider     29  
Miscellaneous revenues (partially offset in O&M)     18  
Estimated impact of weather     16  
Transmission revenues / net of expense     15  
Conservation and non-fuel riders (partially offset in O&M)     13  
Firm wholesale     11  
SPS regulatory settlements, including fuel cost recovery     1  
Purchased capacity costs     (27 )
NSP-Wisconsin fuel cost recovery     (14 )
Other, including sales mix and other fuel recovery     (4 )
   
 
  Total increase in base electric utility margin   $ 219  
   
 

53


2007 Comparison to 2006 — The increase in base electric margin for the year was due to PSCo electric rate increase, the impact of favorable temperatures and weather normalized retail sales growth. These items were partially offset by purchased power costs, NSP-Wisconsin fuel cost recovery and other items.

 
  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 revenues     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 increase in base electric utility margin   $ 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.

Short-Term Wholesale and Commodity Trading Margin

2007 Comparison to 2006 — Short-term wholesale and commodity trading margins decreased approximately $13 million for 2007 compared to 2006. As expected, short-term wholesale margins declined due to retail sales growth, which reduced generation available for sale in the wholesale market.

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.


Natural Gas Utility Revenues and Margins

The following table details the changes in natural gas utility revenues 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.

 
  2007
  2006
  2005
 
 
  (Millions of Dollars)
 
Natural gas utility revenues   $ 2,112   $ 2,156   $ 2,307  
Cost of natural gas purchased and transported     (1,548 )   (1,645 )   (1,823 )
   
 
 
 
  Natural gas utility margin   $ 564   $ 511   $ 484  
   
 
 
 

54


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

Natural Gas Revenues

 
  2007 vs. 2006
  2006 vs. 2005
 
 
  (Millions of Dollars)
 
Purchased natural gas cost recovery   $ (128 ) $ (147 )
Estimated impact of weather     46     (33 )
Base rate changes — all jurisdictions     21     32  
Transportation     6     8  
Sales growth (decline) (excluding weather impact)     2     (8 )
Other, including late payment fees     9     (3 )
   
 
 
  Total decrease in natural gas revenues   $ (44 ) $ (151 )
   
 
 

2007 Comparison to 2006 — Natural gas revenues decreased primarily due to lower natural gas costs in 2007, which are recovered from customers. Interim rate increases were effective for Minnesota in January 2007 and base rates increased for Colorado and North Dakota customers in July 2007.

2006 Comparison to 2005 — Natural gas revenues 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.

Natural Gas Margin

 
  2007 vs. 2006
  2006 vs. 2005
 
 
  (Millions of Dollars)
 
Base rate changes — all jurisdictions   $ 21   $ 32  
Estimated impact of weather     16     (4 )
Transportation     6     8  
Sales growth (decline), excluding weather impact     2     (7 )
Other     8     (2 )
   
 
 
  Total increase in natural gas margin   $ 53   $ 27  
   
 
 

2007 Comparison to 2006 — Natural gas margins increased due to interim rate increases, which were effective for Minnesota in January 2007, and base rate increases for Colorado and North Dakota customers in July 2007.

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.


Non-Fuel Operating Expenses and Other Items

Other Operating and Maintenance Expenses

 
  2007 vs. 2006
 
 
  (Millions of Dollars)
 
Higher combustion/hydro plant costs   $ 33  
Higher nuclear plant operation costs     19  
Recording of private fuel storage regulatory asset in 2006     17  
Higher labor costs     16  
Higher conservation incentive programs (offset in electric margins)     13  
Lower gains/losses on sale or disposal of assets, net     10  
Higher contractor costs     10  
Higher donations, including low income contributions (offset in revenues)     10  
Higher material costs     5  
Lower employee benefit costs     (32 )
Lower nuclear plant outage costs     (10 )
Lower uncollectible receivable costs     (1 )
Other, including licenses and permits     6  
   
 
  Total increase in other operating and maintenance expenses   $ 96  
   
 

55


2007 Comparison to 2006 — The increase in operating and maintenance expenses for 2007 was largely driven by recording a $17 million regulatory asset for private nuclear fuel storage costs which had been previously expensed and higher net gains on sales of assets in 2006. Also, higher combustion/hydro and nuclear plant costs increased operating and maintenance expense. Offsetting these increases in operating and maintenance expenses were lower performance based incentive plan expense as well as lower healthcare expense. Also partially offsetting the increased operating and maintenance expenses were lower nuclear plant outage costs, due to two refueling outages in 2006 versus only one outage in 2007.

 
  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 programs (offset in electric margins)     4  
Other, including fleet transportation and facilities costs     11  
   
 
  Total increase in other operating and maintenance expenses   $ 66  
   
 

2006 Comparison to 2005 — Other operating and maintenance expenses for 2006 increased $66 million, or 3.9 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 sales of assets, and the establishment of the private fuel storage regulatory asset, based on a regulatory decision.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $5 million, or 0.6 percent, for 2007, compared to 2006. Depreciation increased due to capital additions and was largely offset by the MPUC approval of NSP-Minnesota's remaining lives depreciation filing, which lengthened the life of the Monticello nuclear plant by 20 years, as well as certain other smaller plant life adjustments and adjustments to depreciable lives from the Texas rate case settlement. Both of these decisions were effective Jan. 1, 2007, and in total reduced depreciation expense by $45 million for the year.

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.

AFDC — AFDC increased in total by $16 million for 2007 when compared to 2006. The increase was due primarily to large capital projects, including Comanche 3 and a portion of MERP, with long construction periods.

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.

Interest and Other Income (Expense), Net — Interest and other income (expense), net increased $7 million in 2007 compared to 2006. The increase is due primarily to higher interest income on temporary cash investments and the decrease in insurance policy interest expense related to COLI due to the settlement reached with the U.S. Government. In addition, interest and penalties related to the COLI settlement, increased by $43 million in 2007, due to the settlement reached with the U.S. Government.

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 Financing Costs — Interest charges increased by approximately $33 million, or 6.8 percent, for 2007 compared with 2006. The increase is due to higher levels of both short-term and long-term debt and higher interest rates.

56


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.

Income Tax Expense — Income taxes for continuing operations increased by $113 million for 2007, compared with 2006. The increase in income tax expense was primarily due to an increase in pretax income (excluding COLI) and $16.1 million of tax expense related to the COLI settlement in 2007 and $29.9 million of tax benefits from the reversal of a regulatory reserve and realized capital loss carry forwards in 2006. The effective tax rate for 2007 was 33.8 percent, compared with 24.2 percent for the same period in 2006. The higher effective tax rate for 2007 was primarily due to the COLI settlement and the lower effective tax rate for 2006 was primarily due to the recognition of a tax benefit relating to the reversal of a regulatory reserve and realized capital loss carry forwards. Without these charges and benefits, the effective tax rate for 2007 and 2006 would have been 30.3 percent and 28.2 percent, respectively.

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 carry forwards. Without these tax benefits the effective tax rate for 2006 would have been 28.2 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
 
 
  2007
  2006
  2005
 
 
  (Millions of Dollars)
 
Eloigne   $ 2.6   $ 4.6   $ 6.2  
Financing costs — holding company     (71.9 )   (66.1 )   (52.7 )
Holding company, taxes and other results     9.2     24.2     6.2  
   
 
 
 
  Total holding company and other loss — continuing operations   $ (60.1 ) $ (37.3 ) $ (40.3 )
   
 
 
 
 
 
  Contribution to Xcel Energy's earnings per share
 
 
  2007
  2006
  2005
 
Eloigne   $   $ 0.01   $ 0.01  
Financing costs and preferred dividends — holding company     (0.15 )   (0.12 )   (0.09 )
Holding company, taxes and other results     0.03     0.05     0.01  
   
 
 
 
  Total holding company and other loss per share — continuing operations   $ (0.12 ) $ (0.06 ) $ (0.07 )
   
 
 
 

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 2007, 2006 and 2005 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 $10 million in 2007; $15 million in 2006; and $14 million in 2005.

57




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:

 
  2007
  2006
  2005
 
Income (loss) in millions                    
Cheyenne   $   $ 3.0   $ 0.2  
   
 
 
 
  Regulated utility segments — income         3.0     0.2  
NRG     0.4     (0.5 )   16.1  
Xcel Energy International     2.4     (0.5 )   0.1  
e prime         0.1     (0.1 )
Seren     (2.9 )   2.1     1.8  
Utility Engineering Corp. / Quixx Corp.      1.3     (0.7 )   (4.4 )
Other     0.2     (0.4 )   0.2  
   
 
 
 
  Nonregulated/other — income     1.4     0.1     13.7  
   
 
 
 
    Total income from discontinued operations   $ 1.4   $ 3.1   $ 13.9  
   
 
 
 
Income (loss) per share                    
Cheyenne   $   $ 0.01   $  
   
 
 
 
  Regulated utility segments — income per share         0.01      
NRG             0.04  
Xcel Energy International     0.01          
e prime              
Seren     (0.01 )        
Utility Engineering, Corp. / Quixx Corp.              (0.01 )
Other              
   
 
 
 
  Nonregulated/other — income per share             0.03  
   
 
 
 
    Total income per share from discontinued operations   $   $ 0.01   $ 0.03  
   
 
 
 


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.

Tax Benefits Related to Investment in NRG — Xcel Energy has recognized cumulative 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 primarily in discontinued operations.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years due to net operating loss carryforwards. Xcel Energy used $630 million of these deferred tax benefits through 2006, an additional $90 million in 2007, and expects to use approximately $110 million in 2008. 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

58


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 1.7 percent in 2007, and 1.8 percent in 2006. Weather-normalized sales growth for firm natural gas utility customers was approximately 0.8 percent in 2007, and (2.8) percent in 2006. Weather-normalized sales for 2008 are projected to grow between 1.8 percent and 2.2 percent for retail electric utility customers and 0.0 percent to 1.0 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 54 percent and 80 percent of the total annual generation. Approximately 86 percent of the annual coal requirements are supplied from the Powder River Basin in Wyoming.

Pension Plan Costs and Assumptions

Xcel Energy has significant net pension and postretirement benefit costs that are measured using actuarial valuations. Inherent in these valuations are key assumptions including discount rates and expected return on plan assets. Xcel Energy evaluates these key assumptions at least annually by analyzing current market conditions, which includes changes in interest rates and market returns. Changes in the related net pension and post-retirement benefits costs may occur in the future due to changes in assumptions. For further discussion and a sensitivity analysis on these assumptions, see "Employee Benefits" under Critical Accounting Policies and Estimates.

Regulation

PUHCA 2005 — The Energy Act significantly changed many federal statutes. 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.

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 DSM efforts and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in rate proceedings.

Wholesale Energy Market Regulation — In 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. In September 2007, MISO proposed to modify the Day 2 market to establish a regional ASM effective

59



in June 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market. 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 and 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. For wholesale electric transmission services, Xcel Energy has, consistent with FERC policy, implemented or proposed to establish formula rates for each of the utility subsidiaries that will provide annual rate increases as transmission investments increase in a manner similar to the rate riders.

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:

$173 million in 2007;

$152 million in 2006; and

$147 million in 2005.

Xcel Energy expects to expense an average of approximately $201 million per year from 2008 through 2012 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:

$438.6 million in 2007;

$571.2 million in 2006; and

$327.7 million in 2005.

Xcel Energy expects to incur approximately $455 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2008, and approximately $269 million of related expenditures from 2009 through 2012. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado.

Approximately $101 million and $14 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 $156 million in 2008 and $38 million from 2009 through 2012.

The remaining expected capital expenditures relate to various other environmental projects.

In addition, NSP-Minnesota has proposed a $1.1 billion upgrade at the 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 15 to the consolidated financial statements for further discussion of Xcel Energy's environmental contingencies.

Generating facilities throughout the Xcel Energy territory are subject to state-only mercury reduction requirements. In Minnesota mercury emissions from A.S. King and Sherburne County generating facilities will be regulated by the

60



Minnesota Mercury Legislation, and in Colorado, seven units are subject to a mercury emissions rule passed by the Colorado Air Quality Control Commission. These facilities, as well as other generating units, were also subject to regulation under the federal CAMR; however, the D.C. Circuit Court of Appeals vacated this rule on Feb. 8, 2008.

The EPA requires states to develop implementation plans to comply with the BART/Regional Haze Rules by December 2007. At this time, MPCA is not requiring any BART specific controls that go beyond controls required for CAIR compliance. In response to the BART regulations promulgated by the Colorado Air Quality Control Commission, PSCo submitted its BART alternatives analysis, which had been approved by the CAPCD, as well as the Colorado Air Quality Control Commission during a public hearing in December 2007. CAPCD's BART determinations and corresponding provisions of the regional haze state implementation plan will be submitted to the EPA for approval in 2008. 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.

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 to have a significant impact on its results in the future.

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 critical 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.


Regulatory Accounting

Xcel Energy is a holding company with rate-regulated subsidiaries that are subject to the FASB "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). SFAS No. 71 provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates could be charged and collected. Xcel Energy's rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of current and future cash flows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. Regulatory liabilities represent incurred or accrued credits that have been deferred because they will be returned to customers in future rates. In other businesses or industries, regulatory assets would be charged to expense and regulatory liabilities would be recorded as income. As of Dec. 31, 2007 and 2006, Xcel Energy has recorded regulatory assets of approximately $1.1 billion and $1.2 billion and regulatory liabilities of approximately $1.4 billion and $1.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs, in any such jurisdiction, ceases to be probable, Xcel Energy would be required to charge these assets to current earnings. However, there are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. In addition, deregulation would be

61


a change that occurs over time, due to legal processes and procedures, which could moderate the impact to Xcel Energy's consolidated financial statements.

See Note 17 for additional details on regulatory assets and liabilities.


Nuclear Decommissioning

NSP-Minnesota owns nuclear generation facilities and regulations require NSP-Minnesota to decommission its nuclear power plants after each facility is taken out of service. Xcel Energy records future plant removal obligations as a liability at fair value. This liability will be increased over time by applying the interest method of accretion to the liability. Due to regulation, depreciation expense is recorded to match the recovery of future cost of decommissioning, or retirement, of its nuclear generating plants. This recovery is calculated using an annuity approach designed to provide for full rate recovery of the future decommissioning costs.

Amounts recorded for nuclear AROs, in excess of decommissioning expense and investment returns, both realized and unrealized, cumulatively are deferred through the establishment of a regulatory asset for future recovery pursuant to SFAS No. 71.

A portion of the rates charged to customers is deposited into an external trust fund, during the facilities' operating lives, in order to provide for this obligation. The fair value of external nuclear decommissioning trust fund investments are estimated based on quoted market prices for those or similar investments. Realized investment returns from these investments and recovery to date is used by regulators when determining future decommissioning recovery.

NSP-Minnesota conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The costs are initially presented in amounts prior to inflation adjustments and then inflated to future periods using decommissioning specific cost inflators. Decommissioning of NSP-Minnesota's nuclear facilities is planned for the period from cessation of operations through 2050 assuming the prompt dismantlement method. The following key assumptions have a significant effect on these estimates:

Escalation Rate — The MPUC determines the escalation rate based on various presumptions surrounded by the fact that associated costs will escalate at a certain rate over time. The most recent decommissioning study, completed in 2005, set the escalation rate at 3.61 percent. An escalation rate for the cost of disposing of nuclear fuel waste was set at 6.0 percent. Over the short-term, these rates can differ from the set rates and accrual estimates can be significantly affected by small changes in assumed escalation rates.

Life Extension — Currently, decommissioning recovery periods end in 2020 for Monticello and in 2013 and 2014 for Prairie Island's two facilities. Changes made to decommissioning cost estimates, the escalation rate and the earnings rate can be amplified by these short end-of-license life periods. With the recent re-licensing of Monticello and the preparation for re-licensing Prairie Island, any change in license life could have a material effect on the accrual. Under FASB Statement No. 143 — Accounting for AROs (SFAS No. 143), current calculations have assumed full life extension, which brings the regulatory recovery period up to 2020. These adjustments reduced the depreciation expense of NSP-Minnesota by approximately $41 million for the period ended Dec.31, 2007. In addition, the lengthening of the remaining life for the Monticello nuclear plant decreased the related ARO and related regulatory asset by $121 million in the third quarter of 2007. Prairie Island anticipates filing a similar application in 2008, with final state and federal approvals expected in 2010.

Cost Estimate With Spent Fuel Disposal — Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel. NSP-Minnesota has funded its portion of the DOE's permanent disposal program since 1981. The spent fuel storage assumptions have a significant influence on the decommissioning cost estimate. The manner in which spent nuclear fuel is managed and the assumptions used to develop cost estimates of decommissioning programs have a dramatic impact, which in turn can have a corresponding impact on the resulting accrual.

The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The total obligation for decommissioning currently is expected to be funded 100 percent by a portion of the rates charged to customers, as approved by the MPUC. Decommissioning expense recoveries are based upon the same assumptions and methodologies as the fair value obligations are recorded. In addition to these assumptions discussed previously, assumptions related to future earnings of the nuclear decommissioning fund are utilized by the MPUC in determining the recovery of decommissioning costs. Through utilization of the annuity approach, an assumed rate of return on funding is calculated which provides the earnings rate.

62


With a long period of decommissioning and a funding period over the operating lives of each facility, the ability of the fund to sustain the required payments after inflation while assuring the appropriate investment structure is critical in obtaining the best benefit in the accrual. Currently, an assumption that the external funds will earn a return of 5.4 percent, after tax is utilized when setting recovery by the MPUC.

Significant uncertainties exist in estimating the future cost of decommissioning including the method to be utilized, the ultimate costs to decommission, and the planned treatment of spent fuel. Materially different results could be obtained if different assumptions were utilized. Currently, our estimates of future decommissioning costs and the obligation to retire the plants have a significant impact to our financial position. The amounts recorded for AROs and regulatory assets for unrecovered costs are $1,315.1 million and $39.9 million as of December 31, 2007. If different cost estimates, shorter life assumptions or different cost escalation rates were utilized, this ARO and the unrecovered balance in regulatory assets could change materially. If future earnings on the decommissioning fund are lower than that estimated currently, future decommissioning recoveries would need to increase. The significance to our results of operations is reduced due to the fact that we record decommissioning expense based upon recovery amounts approved by our regulators. This treatment reduces the volatility of expense over time. The difference between regulatory funding (including both depreciation expense less returns from the investments fund) and amounts recorded under SFAS No. 143 are deferred as a regulatory asset.


Income Tax Accruals

Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of effective tax rates.

Effective tax rates (ETR) are also highly impacted by assumptions. ETR calculations are revised every quarter based on best available year-end tax assumptions (income levels, deductions, credits, etc.) by legal entity; adjusted in the following year after returns are filed, with the tax accrual estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities have been completed.

In accordance with the interim reporting rules under APB 28, a tax expense or benefit is recorded every quarter to eliminate the difference in continuing operations tax expense computed based on the actual year-to-date ETR and the forecasted annual ETR.

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48), has impacted the income tax accrual process in that the new accounting rule requires that only tax benefits that meet the "more likely than not" recognition threshold can be recognized or continue to be recognized. The change in the unrecognized tax benefits need to be reasonably estimated based on evaluation of the nature of uncertainty, the nature of event that could cause the change and an estimate of range of reasonably possible changes. At any period end, and as new developments occur, management will use prudent business judgment to unrecognize appropriate amounts of tax benefits. Unrecognized tax benefits can be recognized as issues are favorably resolved and loss exposures decline. As required, Xcel Energy adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material.

As disputes with the IRS and state tax authorities are resolved over time, we may need to adjust our unrecognized tax benefits and interest accruals to the updated estimates needed to satisfy tax and interest obligations for the related issues. These adjustments may be favorable or unfavorable, increasing or decreasing earnings.

See Note 7 for further details regarding income taxes.


Employee Benefits

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 10 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.

63


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 2007, 2003 and 2002 were below the assumed level of 8.75, 9.25 and 9.5 percent respectively, and discount rates have increased to 6.00 percent used in 2007. Xcel Energy continually reviews its pension assumptions and, in 2008, expects to maintain the investment return assumption at 8.75 percent and to increase the discount rate assumption to 6.25 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 $11.4 million in 2007 to income of $6.0 million in 2008 and income of $8.4 million in 2009.

Xcel Energy bases its discount rate assumption on benchmark interest rates from Moody's. At Dec. 31, 2007, the annualized Moody's Baa index rate was 6.56 percent, and the Aaa index rate was 5.41 percent. Accordingly, Xcel Energy increased the discount rate to 6.25 percent as of Dec. 31, 2007. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2008 pension cost determinations. At Dec. 31, 2006, the annualized Moody's Baa index rate was 6.35 percent and the Aaa index rate was 5.46 percent. The corresponding pension discount rate was 6.00 percent.

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, Xcel Energy expects to make voluntary contributions in 2007 and 2008 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 10 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. However, all pension costs are expected to be recoverable in rates.

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

 
  Pension Costs
 
  +1%
  -1%
 
  (in millions)
Effect on Dec. 31, 2007 Benefit Obligations:            
  Rate of Return   $ (19.8 ) $ 19.8
  Discount Rate     (4.9 )   6.8

Effective Dec. 31, 2007, Xcel Energy reduced its initial medical trend assumption from 9.0 percent to 8.0 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is 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. See Note 10 for additional discussion of Xcel Energy's benefit plans.

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. 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, 2007.

For a discussion of significant accounting policies, see Note 1 to the consolidated financial statements.


Pending Accounting Changes

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

64


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 consolidated financial statements and does not expect the impact of implementation to be material.

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

Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity's fiscal year that begins on or after Dec. 15, 2008. Xcel Energy is evaluating the impact of SFAS No. 141R on its consolidated financial statements for any potential business combinations subsequent to Jan. 1, 2009.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51(SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent's equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently. This statement is effective for fiscal years beginning on or after Dec. 15, 2008. Xcel Energy is evaluating the impact of SFAS No. 160 on its consolidated financial statements.


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

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 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.

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 and energy and other energy-related instruments. 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 this policy.

65


The fair value of the commodity trading contracts at Dec. 31, 2007, were as follows:

 
  (Millions of Dollars)
 
Fair value of trading contracts outstanding at Jan. 1, 2007   $ (1.2 )
Contracts realized or settled during the year     (14.8 )
Fair value of trading contract additions and changes during the year     22.3  
   
 
Fair value of trading contracts outstanding at Dec. 31, 2007   $ 6.3  
   
 

At Dec. 31, 2007, the fair values by source for the commodity trading net asset or liability balances were as follows:

 
  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
Fair Value

 
 
  (Thousands of Dollars)
 
NSP-Minnesota   1   $ (2,499 ) $   $   $   $ (2,499 )
    2     3,769     980             4,749  
PSCo   1     (657 )               (657 )
    2     3,893     701             4,594  
SPS*   1     63                 63  
    2     163     38             201  
       
 
 
 
 
 
Total Futures/Forwards Fair Value       $ 4,732   $ 1,719   $   $   $ 6,451  
       
 
 
 
 
 
 
 
  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   $ (139 ) $   $   $   $ (139 )
SPS*   2     3                 3  
       
 
 
 
 
 
Total Options Fair Value       $ (136 ) $   $   $   $ (136 )
       
 
 
 
 
 

(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, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

At Dec. 31, 2007, a 10-percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.1 million, whereas a 10-percent decrease would decrease pretax income from continuing operations by approximately $0.1 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.

66


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

 
   
  During 2007
 
  Year ended
Dec. 31, 2007

 
  Average
  High
  Low
 
   
  (Millions of Dollars)
Commodity trading(a)   $ 0.26   $ 0.47   $ 1.45   $ 0.09
 
 
   
  During 2006
 
  Year ended
Dec. 31, 2006

 
  Average
  High
  Low
 
   
  (Millions of Dollars)
Commodity trading(a)   $ 0.49   $ 1.32   $ 2.60   $ 0.39

(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 risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At Dec. 31, 2007, a 100-basis-point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense by approximately $12.7 million. See Note 12 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. At Dec. 31, 2007, 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, 2007, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $19.6 million, while a decrease of 10 percent would have resulted in a decrease of $12.0 million.


Liquidity and Capital Resources

Cash Flows

 
  2007
  2006
  2005
 
  (Millions of Dollars)
Cash provided by operating activities                  
Continuing operations   $ 1,500   $ 1,729   $ 1,131
Discontinued operations     72     195     53
   
 
 
  Total   $ 1,572   $ 1,924   $ 1,184
   
 
 

Cash provided by operating activities for continuing operations decreased $229 million during 2007. The decrease was primarily due to changes in working capital activity primarily the timing of accounts receivables and unbilled revenues. The decrease in cash provided by operations was partially offset by the collection of recoverable purchased natural gas and electric energy costs. Cash provided by operating activities for discontinued operations decreased $123 million during 2007, largely due to the sale of related assets.

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

67



operations was partially offset by the timing of cash expenditures for accounts payable. Cash provided by operating activities for discontinued operations increased $142 million during 2006, largely due to the realization of deferred tax assets related to NRG.

 
  2007
  2006
  2005
 
 
  (Millions of Dollars)
 
Cash provided by (used in) investing activities                    
Continuing operations   $ (2,023 ) $ (1,601 ) $ (1,362 )
Discontinued operations         51     136  
   
 
 
 
  Total   $ (2,023 ) $ (1,550 ) $ (1,226 )
   
 
 
 

Cash used in investing activities for continuing operations increased $422 million during 2007, primarily due to increased utility capital expenditures, partially offset by the cash obtained from the consolidation of NMC and the sale of certain investments in the nuclear decommissioning trust fund. No cash was provided by investing activities for discontinued operations.

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 $85 million during 2006, primarily due to the receipt of proceeds from the sale of Cheyenne and Seren in 2005.

 
  2007
  2006
  2005
 
  (Millions of Dollars)
Cash provided by (used in) financing activities                  
Continuing operations   $ 483   $ (422 ) $ 111
   
 
 
  Total   $ 483   $ (422 ) $ 111
   
 
 

Cash flow from financing activities related to continuing operations increased $905 million during 2007 due to increased short-term borrowings as well as a decrease in the repayments of long-term debt.

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.

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 2008 through 2011 are shown in the tables below.

By Segment

  2008
  2009
  2010
  2011
Electric utility   $ 1,880   $ 1,375   $ 1,465   $ 1,775
Natural gas utility     145     160     160     150
Common utility and other     75     65     75     75
   
 
 
 
  Total capital expenditures     2,100     1,600     1,700     2,000
Debt maturities     638     558     542     52
   
 
 
 
  Total capital requirements   $ 2,738   $ 2,158   $ 2,242   $ 2,052
   
 
 
 
 
By Utility Subsidiary

  2008
  2009
  2010
  2011
NSP-Minnesota   $ 1,005   $ 805   $ 910   $ 1,190
NSP-Wisconsin     100     90     80     80
PSCo     825     505     530     590
SPS     170     200     180     140
   
 
 
 
  Total   $ 2,100   $ 1,600   $ 1,700   $ 2,000
   
 
 
 

68


 
By Project

  2008
  2009
  2010
  2011
Base and other capital expenditures   $ 1,095   $ 1,135   $ 1,170   $ 1,170
MERP     170     25     10    
Comanche 3     330     60     10    
Minnesota wind/CapX 2020 transmission     40     65     115     300
Sherco capacity increases     5     20     75     230
Minnesota wind generation     135            
Nuclear capacity increases and life extension     75     120     180     200
Nuclear fuel     150     150     140     100
Fort St. Vrain CT     100     25        
   
 
 
 
  Total committed capital expenditures   $ 2,100   $ 1,600   $ 1,700   $ 2,000
Potential projects     0-100     200-400     200-400     200-500
   
 
 
 
Range   $ 2,100-2,200   $ 1,800-2,000   $ 1,900-2,100   $ 2,200-2,500
   
 
 
 

Many of the states in which Xcel Energy operates have enacted 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 renewable generation and transmission assets. The other potential projects included in the table above represent wind generation, natural gas generation and transmission projects that may result from the Colorado and Minnesota resource plans that were filed in the fourth quarter of 2007. These potential projects will require commission approval.

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, 2007. See additional discussion in the consolidated statements of capitalization and Notes 4, 5, and 15 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   $ 12,599,312   $ 1,065,530   $ 1,849,818   $ 1,760,489   $ 7,923,475
Capital lease obligations     85,951     6,139     11,794     11,139     56,879
Operating leases(a), (b)     1,439,346     104,557     200,000     161,743     973,046
Unconditional purchase obligations     12,047,364     2,448,155     3,321,234     2,247,977     4,029,998
Other long-term obligations — WYCO investment     121,000     108,000     13,000        
Other long-term obligations(c)     165,847     31,589     42,775     38,964     52,519
Payments to vendors in process     145,059     145,059            
Short-term debt     1,088,560     1,088,560            
   
 
 
 
 
  Total contractual cash obligations(d)   $ 27,692,439   $ 4,997,589   $ 5,438,621   $ 4,220,312   $ 13,035,917
   
 
 
 
 

(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 $176.8 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.

69


(b)
Included in operating lease payments are $76.6 million, $151.7 million, $124.5 million and $916.6 million, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to five purchase power agreements that were accounted for as operating leases.
(c)
Included in other long-term obligations are tax, penalties and interest related to unrecognized tax benefits recorded according to FIN 48.
(d)
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. The effects of price changes are mitigated through cost-of-energy adjustment mechanisms.
(e)
Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $1.6 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

Xcel Energy has also executed five additional purchase power agreements that are conditional upon achievement of certain conditions, including becoming operational. Estimated payments under these conditional obligations are $52.8 million, $165.7 million, $177.9 million and $1.7 billion, respectively, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories.

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, 2007, was 85 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, working capital and dividend payments.

70


As of Feb. 15, 2008, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

 
  Facility
  Drawn*
  Available
  Cash
  Liquidity
  Maturity
 
  (Million of Dollars)
NSP-Minnesota   $ 500   $ 323.4   $ 176.6   $ 8.7   $ 185.3   December 2011
PSCo     700     184.2     515.8     125.9     641.7   December 2011
SPS     250     103.0     147.0     0.3     147.3   December 2011
Xcel Energy — holding company     800     179.8     620.2     4.6     624.8   December 2011
   
 
 
 
 
   
  Total   $ 2,250   $ 790.4   $ 1,459.6   $ 139.5   $ 1,599.1    
   
 
 
 
 
   

*
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; supply and operational uncertainties and other changes in working capital, 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 4 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. 15, 2008, 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   A-
PSCo   Senior Secured Debt   A3   A   A
PSCo   Commercial Paper   P-2   A-2   F2
SPS   Senior Unsecured Debt   Baa1   BBB+   BBB+
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 13 to the consolidated financial statements. Xcel Energy has no explicit credit rating requirements in its debt agreements.

Money Pool — Xcel Energy received 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.

71


The borrowings or loans outstanding at Dec. 31, 2007, and the SEC approved short-term borrowing limits from the money pool are as follows (millions):

 
  Borrowings
(Loans)

  Total Borrowing
Limits

NSP-Minnesota   $ (95.1 ) $ 250
PSCo     100.6     250
SPS     (5.5 )   100

Registration Statements — Xcel Energy's articles of incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2007, Xcel Energy had approximately 429 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, 2007, 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 an effective automatic shelf registration statement that does not contain a limit on issuance capacity; however, Xcel Energy's ability to issue securities is limited by authority granted by the Board of Directors, which authority currently authorizes the issuance of up to an additional $1.1 billion of debt securities.

NSP-Minnesota has $1.5 billion of debt securities available under its current effective registration statement.

PSCo has approximately $850 million of debt securities available under its currently effective registration statement.


Future Financing Plans

Xcel Energy generally expects to fund its operations and capital investments primarily through internally generated funds. Xcel Energy expects to convert the $57.5 million principal balance of its Senior Convertible Notes due Nov. 21, 2008, to common equity by the maturity date of the notes. Xcel Energy plans to issue commercial paper to meet short-term working capital requirements.

During 2008, Xcel Energy plans to issue debt securities at several of its operating companies. These financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors. Current debt financing plans include the following:

NSP-Minnesota plans to issue between $400-$500 million of long-term senior debt securities to refinance outstanding commercial paper, to fund utility capital expenditures and to provide funds for general corporate purposes. NSP-Minnesota plans to issue commercial paper to meet short-term working capital requirements, including funding for inter-company loans to NSP-Wisconsin.

PSCo plans to issue between $500-$600 million of long-term senior debt securities to refinance a $300 million long-term debt maturity, to refinance outstanding commercial paper, to fund utility capital expenditures and to provide funds for general corporate purposes. PSCo plans to issue commercial paper to meet short-term working capital requirements.

NSP-Wisconsin plans to issue up to $250 million of long-term senior debt securities to refinance an $80 million long-term debt maturity, to repay outstanding short-term debt, to fund utility capital expenditures and to provide funds for general corporate purposes. NSP-Wisconsin plans to issue inter-company notes to NSP-Minnesota to meet short-term working capital requirements.


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.

72



Earnings Guidance

Xcel Energy's 2008 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

 
  2008 Diluted Earnings Per Share
Range

 
Utility operations   $ 1.61 - $1.71  
Holding company financing costs and other     (0.16 )
   
 
  Xcel Energy Continuing Operations   $ 1.45 - $1.55  
   
 

Key Assumptions for 2008:

Normal weather patterns are experienced during the year.

Regulatory approval of various riders associated with MERP, Minnesota and Colorado transmission and Minnesota renewable energy, which are expected to increase revenue by approximately $60 million to $70 million over the projected 2007 levels.

Reasonable regulatory outcomes in the New Mexico electric rate case, Texas electric rate case and North Dakota electric rate case.

No material incremental accruals related to the SPS regulatory proceedings.

Weather-adjusted retail electric utility sales grow by approximately 1.8 percent to 2.2 percent.

Weather-adjusted retail firm natural gas sales grow by approximately 0.0 percent to 1.0 percent.

Short-term wholesale and commodity trading margins are within a range of $20 million to $30 million.

Capacity costs at NSP-Minnesota and SPS are projected to increase approximately $45 million to $55 million over 2007 levels. We expect regulatory recovery of approximately $11 million of the increase in capacity costs at SPS. Capacity costs at PSCo are recovered under the PCCA.

Utility operating and maintenance expenses increase between 2 percent and 3 percent.

Depreciation expense is projected to increase approximately $60 million to $70 million over 2007 levels.

Interest expense increases approximately $25 million to $35 million over 2007 levels.

Allowance for funds used during construction-equity increases approximately $35 million to $45 million over 2007 levels.

An effective tax rate for continuing operations of approximately 32 percent to 35 percent.

Average common stock and equivalents for diluted earnings per share calculations of approximately 438 million shares.


Item 7A — Quantitative and Qualitative Disclosures About Market Risk

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

73



Item 8 — Financial Statements and Supplementary Data

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

See Note 19 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, 2007. 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, 2007, 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 the company's internal control over financial reporting. Their report appears on the following page.

/S/ RICHARD C. KELLY
Richard C. Kelly
Chairman, President and Chief Executive Officer
February 20, 2008
      /S/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
February 20, 2008

74


Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited the accompanying consolidated balance sheets and statements of capitalization of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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 7 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, "Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109," as of January 1, 2007. As discussed in Note 10 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 Company's internal control over financial reporting as of December 31, 2007, 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 20, 2008 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 20, 2008

75


Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited the internal control over financial reporting of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2007, 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, included in the accompanying Management Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007 of the Company and our report dated February 20, 2008 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of new accounting standards.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 20, 2008

76



XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Income
(thousands of dollars, except per share data)

 
  Year ended Dec. 31
 
 
  2007
  2006
  2005
 
Operating revenues                    
  Electric utility   $ 7,847,992   $ 7,608,018   $ 7,243,637  
  Natural gas utility     2,111,732     2,155,999     2,307,385  
  Other     74,446     76,287     74,455  
   
 
 
 
    Total operating revenues     10,034,170     9,840,304     9,625,477  
Operating expenses                    
  Electric fuel and purchased power — utility     4,136,994     4,103,055     3,922,163  
  Cost of natural gas sold and transported — utility     1,547,622     1,644,716     1,823,123  
  Cost of sales — other     24,370     24,388     24,676  
  Other operating and maintenance expenses     1,869,215     1,773,526     1,707,665  
  Depreciation and amortization     827,173     821,898     767,321  
  Taxes (other than income taxes)     277,723     295,727     287,810  
   
 
 
 
    Total operating expenses     8,683,097     8,663,310     8,532,758  
   
 
 
 
Operating income     1,351,073     1,176,994     1,092,719  
  Interest and other income, net     10,948     4,085     857  
  Allowance for funds used during construction — equity     37,207     25,045     21,627  
Interest charges and financing costs                    
  Interest charges — includes other financing costs of $21,410, $24,187 and $25,829, respectively     520,037     486,967     463,370  
  Interest and penalties related to COLI settlement     43,401          
  Allowance for funds used during construction — debt     (34,593 )   (30,935 )   (20,744 )
   
 
 
 
    Total interest charges and financing costs     528,845     456,032     442,626  
   
 
 
 
Income from continuing operations before income taxes     870,383     750,092     672,577  
Income taxes     294,484     181,411     173,539  
   
 
 
 
Income from continuing operations     575,899     568,681     499,038  
Income from discontinued operations — net of tax     1,449     3,073     13,934  
   
 
 
 
Net income     577,348     571,754     512,972  
Dividend requirements on preferred stock     4,241     4,241     4,241  
   
 
 
 
Earnings available to common shareholders   $ 573,107   $ 567,513   $ 508,731  
   
 
 
 
Weighted average common shares outstanding                    
  Basic     416,139     405,689     402,330  
  Diluted     433,131     429,605     425,671  
Earnings per share — basic                    
  Income from continuing operations   $ 1.38   $ 1.39   $ 1.23  
  Income from discontinued operations         0.01     0.03  
   
 
 
 
    Earnings per share   $ 1.38   $ 1.40   $ 1.26  
   
 
 
 
Earnings per share — diluted                    
  Income from continuing operations   $ 1.35   $ 1.35   $ 1.20  
  Income from discontinued operations         0.01     0.03  
   
 
 
 
    Earnings per share   $ 1.35   $ 1.36   $ 1.23  
   
 
 
 
Cash dividends declared per common share   $ 0.91   $ 0.88   $ 0.85  

77



XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(thousands of dollars)

 
  Year ended Dec. 31
 
 
  2007
  2006
  2005
 
Operating activities                    
Net income   $ 577,348   $ 571,754   $ 512,972  
Remove income from discontinued operations     (1,449 )   (3,073 )   (13,934 )
Adjustments to reconcile net income to cash provided by operating activities:                    
  Depreciation and amortization     855,897     857,129     782,074  
  Nuclear fuel amortization     53,453     47,531     45,330  
  Deferred income taxes     265,277     (59,843 )   205,058  
  Amortization of investment tax credits     (8,680 )   (9,806 )   (11,620 )
  Allowance for equity funds used during construction     (37,207 )   (25,045 )   (21,627 )
  Undistributed equity in earnings of unconsolidated affiliates     (1,900 )   (2,775 )   (712 )
  Gain or write down of assets sold or held for sale         (6,189 )   2,887  
  Share-based compensation expense     22,871     40,384     27,598  
  Net realized and unrealized hedging and derivative transactions     6,463     (27,219 )   9,715  
  Changes in operating assets and liabilities (net of effects of consolidation of NMC)                    
    Accounts receivable     (79,373 )   176,732     (250,305 )
    Accrued unbilled revenues     (217,659 )   99,716     (178,585 )
    Inventories     (25,464 )   28,967     (94,605 )
    Recoverable purchased natural gas and electric energy costs     185,185     136,470     (130,442 )
    Other current assets     (9,922 )   (1,831 )   2,002  
    Accounts payable     (10,018 )   (105,707 )   281,430  
    Net regulatory assets and liabilities     27,428     (34,211 )   (20,433 )
    Other current liabilities     52,771     97,216     15,927  
  Change in other noncurrent assets     (56,053 )   4,956     (39,995 )
  Change in other noncurrent liabilities     (99,098 )   (56,415 )   7,699  
Operating cash flows provided by discontinued operations     72,346     195,255     53,283  
   
 
 
 
    Net cash provided by operating activities     1,572,216     1,923,996     1,183,717  
Investing activities                    
  Utility capital/construction expenditures     (2,095,721 )   (1,626,000 )   (1,304,468 )
  Allowance for equity funds used during construction     37,207     25,045     21,627  
  Purchase of investments in external decommissioning fund     (712,462 )   (1,288,103 )   (576,001 )
  Proceeds from the sale of investments in external decommissioning fund     669,070     1,240,034     494,529  
  Nonregulated capital expenditures and asset acquisitions     (1,136 )