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Xcel Energy Inc – ‘10-K’ for 12/31/09

On:  Friday, 2/26/10, at 4:23pm ET   ·   For:  12/31/09   ·   Accession #:  1047469-10-1536   ·   File #:  1-03034

Previous ‘10-K’:  ‘10-K’ on 2/27/09 for 12/31/08   ·   Next:  ‘10-K’ on 2/28/11 for 12/31/10   ·   Latest:  ‘10-K’ on 2/21/20 for 12/31/19   ·   2 Referenced via Accession #:  

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 2/26/10  Xcel Energy Inc                   10-K       12/31/09   53:8.9M                                   Merrill Corp/New/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML   2.22M 
 2: EX-10.24    Material Contract                                   HTML     22K 
 3: EX-12.01    Statement re: Computation of Ratios                 HTML     42K 
 4: EX-21.01    Subsidiaries of the Registrant                      HTML     27K 
 5: EX-23.01    Consent of Experts or Counsel                       HTML     24K 
 6: EX-24.01    Power of Attorney                                   HTML     39K 
 7: EX-31.01    Certification per Sarbanes-Oxley Act (Section 302)  HTML     24K 
 8: EX-31.02    Certification per Sarbanes-Oxley Act (Section 302)  HTML     24K 
 9: EX-32.01    Certification per Sarbanes-Oxley Act (Section 906)  HTML     20K 
10: EX-99.01    Miscellaneous Exhibit                               HTML     23K 
50: EXCEL       XBRL IDEA Workbook -- Financial Report (.xls)        XLS    220K 
42: XML         XBRL XML File -- Definitions and References          XML    126K 
49: XML         XBRL XML File -- Filing Summary                      XML    158K 
47: XML.R1      Consolidated Statements of Income                    XML    362K 
48: XML.R2      Consolidated Statements of Income (Parenthetical)    XML     49K 
28: XML.R3      Consolidated Statements of Cash Flows                XML    504K 
33: XML.R4      Consolidated Balance Sheets                          XML    323K 
40: XML.R5      Consolidated Statements of Common Stockholders'      XML    531K 
                          Equity and Comprehensive Income                        
39: XML.R6      Consolidated Statements of Common Stockholders'      XML     73K 
                          Equity and Comprehensive Income                        
                          (Parenthetical)                                        
52: XML.R7      Consolidated Statements of Capitalization,           XML   2.19M 
                          Long-Term Debt                                         
22: XML.R8      Consolidated Statements of Capitalization, Equity    XML    288K 
38: XML.R9      Consolidated Statements of Capitalization, Equity    XML     72K 
                          (Parenthetical)                                        
20: XML.R10     Summary of Significant Accounting Policies           XML     73K 
19: XML.R11     Accounting Pronouncements                            XML     45K 
27: XML.R12     Selected Balance Sheet Data                          XML     59K 
44: XML.R13     Discontinued Operations                              XML     50K 
29: XML.R14     Short-Term Borrowings and Other Financing            XML     35K 
                          Instruments                                            
30: XML.R15     Long-Term Borrowings and Other Financing             XML     73K 
                          Instruments                                            
36: XML.R16     Generating Plant Ownership and Operation             XML     70K 
53: XML.R17     Income Taxes                                         XML    142K 
25: XML.R18     Preferred and Common Stock                           XML     92K 
17: XML.R19     Share-Based Compensation                             XML    139K 
32: XML.R20     Benefit Plans and Other Postretirement Benefits      XML    270K 
43: XML.R21     Other Income, Net                                    XML     43K 
23: XML.R22     Derivative Instruments                               XML    152K 
41: XML.R23     Financial Instruments                                XML     65K 
31: XML.R24     Fair Value Measurements                              XML    110K 
51: XML.R25     Rate Matters                                         XML    106K 
46: XML.R26     Commitments and Contingent Liabilities               XML    218K 
34: XML.R27     Nuclear Obligations                                  XML     64K 
37: XML.R28     Regulatory Assets and Liabilities                    XML     87K 
18: XML.R29     Segments and Related Information                     XML     93K 
21: XML.R30     Summarized Quarterly Financial Data (Unaudited)      XML     65K 
24: XML.R31     Lubbock Electric Distribution Assets                 XML     34K 
26: XML.R32     Condensed Financial Statements of Xcel Energy Inc.   XML    124K 
35: XML.R33     Valuation and Qualifying Accounts                    XML     44K 
45: XML.R34     Document and Entity Information                      XML    129K 
11: EX-101.INS  XBRL Instance -- xel-20091231                        XML   2.29M 
13: EX-101.CAL  XBRL Calculations -- xel-20091231_cal                XML    205K 
14: EX-101.DEF  XBRL Definitions -- xel-20091231_def                 XML    194K 
15: EX-101.LAB  XBRL Labels -- xel-20091231_lab                      XML   1.03M 
16: EX-101.PRE  XBRL Presentations -- xel-20091231_pre               XML    524K 
12: EX-101.SCH  XBRL Schema -- xel-20091231                          XSD    115K 


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Part I
"Item 1
"Business
"Definition of Abbreviations and Industry Terms
"Company Overview
"Electric Utility Operations
"Electric Utility Trends
"NSP-Minnesota
"NSP-Wisconsin
"PSCo
"Natural Gas Utility Operations
"Natural Gas Utility Trends
"Xcel Energy Natural Gas Operating Statistics
"Environmental Matters
"Capital Spending and Financing
"Employees
"Executive Officers
"Item 1A
"Risk Factors
"Item 1B
"Unresolved Staff Comments
"Item 2
"Properties
"Sps
"Item 3
"Legal Proceedings
"Item 4
"Submission of Matters to a Vote of Security Holders
"Part Ii
"Item 5
"Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
"Item 6
"Selected Financial Data
"Item 7
"Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 7A
"Quantitative and Qualitative Disclosures about Market Risk
"Item 8
"Financial Statements and Supplementary Data
"Xcel Energy Electric Operating Statistics
"Item 9
"Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
"150
"Item 9A
"Controls and Procedures
"Item 9B
"Other Information
"Part Iii
"Item 10
"Directors, Executive Officers and Corporate Governance
"151
"Item 11
"Executive Compensation
"Item 12
"Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
"Item 13
"Certain Relationships and Related Transactions, and Director Independence
"Item 14
"Principal Accountant Fees and Services
"Part Iv
"Item 15
"Exhibits and Financial Statement Schedules
"152
"Signatures
"162

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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 December 31, 2009
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   41-0448030
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer Identification No.)

414 Nicollet Mall
Minneapolis, MN 55401
(Address of principal executive offices)

Registrant's telephone number, including area code: 612-330-550

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

Title of each class   Name of each exchange on which registered
Common Stock, $2.50 par value per share   New York
Rights to Purchase Common Stock, $2.50 par value per share   New York
Cumulative Preferred Stock, $100 par value:    
Preferred Stock $3.60 Cumulative   New York
Preferred Stock $4.08 Cumulative   New York
Preferred Stock $4.10 Cumulative   New York
Preferred Stock $4.11 Cumulative   New York
Preferred Stock $4.16 Cumulative   New York
Preferred Stock $4.56 Cumulative   New York
7.60 Junior Subordinated Notes, Series due 2068   New York

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

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

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

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

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

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 Exchange Act. ý Large accelerated filer o Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller Reporting Company

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

        As of June 30, 2009, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $8,389,744,889 and there were 455,716,724 shares of common stock outstanding.

        As of Feb. 22, 2010, there were 458,171,771 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

        The Registrant's Definitive Proxy Statement for its 2010 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

  9

     

        Electric Utility Trends

  9

     

        NSP-Minnesota

  10

     

        NSP-Wisconsin

  16

     

        PSCo

  18

     

        SPS

  21

     

        Xcel Energy Electric Operating Statistics

  26

     

    NATURAL GAS UTILITY OPERATIONS

  27

     

        Natural Gas Utility Trends

  27

     

        NSP-Minnesota

  27

     

        NSP-Wisconsin

  28

     

        PSCo

  29

     

        Xcel Energy Natural Gas Operating Statistics

  31

     

    ENVIRONMENTAL MATTERS

  31

     

    CAPITAL SPENDING AND FINANCING

  31

     

    EMPLOYEES

  32

     

    EXECUTIVE OFFICERS

  32

  Item 1A —  

Risk Factors

  34

  Item 1B —  

Unresolved Staff Comments

  41

  Item 2 —  

Properties

  42

  Item 3 —  

Legal Proceedings

  44

  Item 4 —  

Submission of Matters to a Vote of Security Holders

  45

PART II

  Item 5 —  

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  45

  Item 6 —  

Selected Financial Data

  47

  Item 7 —  

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

  48

  Item 7A —  

Quantitative and Qualitative Disclosures about Market Risk

  80

  Item 8 —  

Financial Statements and Supplementary Data

  80

  Item 9 —  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  150

  Item 9A —  

Controls and Procedures

  150

  Item 9B —  

Other Information

  150

PART III

  Item 10 —  

Directors, Executive Officers and Corporate Governance

  151

  Item 11 —  

Executive Compensation

  151

  Item 12 —  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  151

  Item 13 —  

Certain Relationships and Related Transactions, and Director Independence

  151

  Item 14 —  

Principal Accountant Fees and Services

  151

PART IV

  Item 15 —  

Exhibits and Financial Statement Schedules

  152

SIGNATURES

  162

2


Table of Contents


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 Company, a Minnesota corporation which invests in rental housing projects that qualify for low-income housing tax credits.
NCE   New Century Energies, Inc.
NMC   Nuclear Management Company, LLC, a wholly owned subsidiary of NSP Nuclear Corporation
NRG   NRG Energy, Inc., a Delaware corporation and independent power producer
NSP-Minnesota   Northern States Power Company, a Minnesota corporation
NSP-Wisconsin   Northern States Power Company, a Wisconsin corporation
PSCo   Public Service Company of Colorado, a Colorado corporation
PSRI   P.S.R. Investments, Inc., a manager of corporate owned life insurance policies
SPS   Southwestern Public Service 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 L.L.C., a joint venture formed with Colorado Interstate Gas Company to develop and lease natural gas pipeline, storage, and compression facilities
Xcel Energy   Xcel Energy Inc., a Minnesota corporation

Federal and State Regulatory Agencies

 

 
ASLB   Atomic Safety and Licensing Board
CAPCD   Colorado Air Pollution Control Division
CPUC   Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo's operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
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
MPCA   Minnesota Pollution Control Agency
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.
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.
NERC   North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U. S. FERC and government authorities in Canada, to develop and enforce reliability standards.
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.
NRC   Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
OES   Office of Energy Security, Minnesota Department of Commerce.
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.

3


Table of Contents

SEC   Securities and Exchange Commission
WDNR   Wisconsin Department of Natural Resources

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. Allows PSCo to recover its actual fuel and purchased energy expense in a calendar year to a benchmark formula. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA.
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.
OATT   Open Access Transmission Tariff
PCCA   Purchased capacity cost adjustment. Allows PSCo to recover from retail customers for all purchased capacity payments to power suppliers, effective Jan. 1, 2007. Capacity charges are not included in PSCo's electric rates or other recovery mechanisms.
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 the PSCo electric utility provides for bill credits to customers based on operational performance standards through Dec. 31, 2010. The QSP for the PSCo natural gas utility also expires Dec. 31, 2010.
RES   Renewable energy standard
RESA   Renewable energy standard adjustment
SCA   Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.
SEP   State Energy Policy
TCR   Transmission cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota's 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

 

 
ACES   American Clean Energy and Security Act
AEP   American Electric Power
AFUDC   Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ   Administrative law judge. A judge presiding over regulatory proceedings.
ARC   Aggregator of Retail Customers
ARO   Asset retirement obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC   FASB Accounting Standards Codification
ASM   Ancillary Services Market
BACT   Best Available Control Technology
BART   Best Available Retrofit Technology

4


Table of Contents

CAA   Clean Air Act
CAIR   Clean Air Interstate Rule
CAMR   Clean Air Mercury Rule
CapX 2020   An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
CIP   Conservation improvement program
CO2   Carbon dioxide
Codification   FASB Accounting Standards Codification
COLI   Corporate owned life insurance
CON   Certificate of need
CWIP   Construction work in progress
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.
DOI   Division of Investigation
EECRF   Energy efficiency cost recovery factor
EPS   Earnings per share of common stock outstanding
ETR   Effective tax rate
FASB   Financial Accounting Standards Board
Fitch   Fitch Ratings
FTRs   Financial transmission rights. Used to hedge the costs associated with transmission congestion.
GAAP   Generally accepted accounting principles
generation   The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in MW (capacity) or MW hours (energy).
GHG   Greenhouse gas
IRP   Integrated Resource Plan
LIBOR   London Interbank Offered Rate
LLW   Low-level radioactive waste
LNG   Liquefied natural gas. Natural gas that has been converted to a liquid.
MACT   Maximum Achievable Control Technology
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.
MOAG   Minnesota Office of Attorney General
Moody's   Moody's Investors Service
native load   The customer demand of retail and wholesale customers that 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.
NOL   Net operating loss
nonutility   All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
NOx   Nitrogen oxide
O&M   Operating and maintenance
OCI   Other comprehensive income
PBRP   Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
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.
PIIC   Prairie Island Indian Community

5


Table of Contents

PJM   Pennsylvania-New Jersey-Maryland Interconnection
PSP   Performance share plan
PURPA   Public Utility Regulatory Policies Act of 1978
rate base   The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
REC   Renewable energy credit
RECB   Regional Expansion Criteria Benefits
RFP   Request for Proposal
ROE   Return on equity
RPS   Renewable Portfolio Standard, is a regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO   Regional Transmission Organization. An independent entity, which is established to have "functional control" over a utility's electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SO2   Sulfur dioxide
SPP   Southwest Power Pool, Inc.
Standard & Poor's   Standard & Poor's Ratings Services
TSR   Total shareholder return
unbilled revenues   Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying   A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission   An electric service wherein high-voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
working capital   Funds necessary to meet operating expenses.

Measurements

 

 
Bcf   Billion cubic feet
Btu   British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
GWh   Gigawatt hours. One gigawatt hour equals one billion watt hours.
KV   Kilovolts (one KV equals one thousand volts)
KW   Kilowatts (one KW equals one thousand watts)
Kwh   Kilowatt hours
Mcf   Thousand cubic feet
MMBtu   One million Btus
MW   Megawatts (one MW equals one thousand KW)
Volt   The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt   A measure of power production or usage.

6


Table of Contents


COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2009, 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 joint venture formed with Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, 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 website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are 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 website.

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. Xcel Energy is implementing resource plans in Colorado and Minnesota that are designed to result in a significant reduction in GHG 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 renewable energy mandates and take advantage of 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 its total sales in 2009. 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 89 percent of NSP-Minnesota's retail electric operating revenues were derived from operations in Minnesota during 2009. Generally, NSP-Minnesota's earnings range from 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 Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation.


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 its total sales in 2009. 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 249,000 customers and natural gas utility service to approximately 105,000 customers. The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota. Approximately 98 percent of NSP-Wisconsin's retail electric operating revenues were derived from operations in Wisconsin during 2009. Generally, NSP-Wisconsin's earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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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 20 percent of its total sales in 2009. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers. All of PSCo's retail electric operating revenues were derived from operations in Colorado during 2009. Generally, PSCo's earnings range from approximately 45 percent to 55 percent of Xcel Energy's consolidated net income.

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


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 36 percent of its total sales in 2009. SPS provides electric utility service to approximately 396,000 retail customers in Texas and New Mexico. Approximately 74 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2009. Generally, SPS' earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

In November 2009, SPS announced it had entered into an agreement to sell certain SPS electric distribution assets in Lubbock, Texas to Lubbock Power and Light (LP&L) for a price of $87 million. SPS' retail sales in Lubbock are 3 percent of SPS' total energy sales. SPS anticipates it will sell the same amount of power to the city under existing wholesale power arrangements with the West Texas Municipal Power Agency.


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 formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. WYCO's High Plains gas pipeline began operations in 2008 and its Totem gas storage facilities began operations in 2009. The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.

Xcel Energy Services Inc. is the service company for the Xcel Energy holding company.

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

Xcel Energy had several other subsidiaries that were sold or divested. For more information regarding Xcel Energy's discontinued operations, see Note 4 to the consolidated financial statements.

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 are set forth in Note 20 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, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. For more information regarding Xcel Energy's capital expenditures, see Note 17 to the consolidated financial statements.

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ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

Climate Change and Clean EnergyLike most other utilities, Xcel Energy is subject to a significant array of environmental regulations. Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. Our operating subsidiaries are subject to state RPS requirements which we believe they will be in a position to achieve by the applicable state deadlines. Although the exact form and design of any federal RPS policy is uncertain at this time, we believe that we will be well-positioned to meet a federal standard as well, although the ultimate design of any federal policy could have a varied impact on each of our operating subsidiaries depending upon the energy efficiency and other standards imposed. In addition, Xcel Energy's electric generating facilities have been and are likely to be further subject to climate change legislation introduced at either the state or federal level within the next few years. In 2009, the EPA took a number of steps toward the regulation of GHGs under the CAA. By spring 2010, the EPA expects to promulgate regulations to control GHGs from mobile sources. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.

While Xcel Energy is not currently subject to state or federal limits on its GHG emissions, Xcel Energy has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on Xcel Energy will depend on the specifics of state and federal policies, legislation, and regulation, 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 CompetitionThe 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. In 2008, the FERC approved a MISO proposal to begin operation of a regional ASM in January 2009.

The FERC has approved the open access transmission planning processes for the Xcel Energy operating companies and the RTOs serving the NSP-Minnesota, NSP-Wisconsin and SPS systems (MISO and SPP, respectively).

NSP-Minnesota received MPUC approval in 2008 to construct three new 115 KV transmission lines in 2009 to deliver additional wind generation even if NSP-Minnesota does not purchase the generation. Several additional transmission expansion projects are pending final MPUC action, including the CapX 2020 expansion.

PSCo is pursuing upgrades to its transmission system and the systems of neighboring utilities in order to facilitate renewable energy expansion, in response to statutory changes enacted in 2007.

SPS is also 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 in the SPP. Transmission expansion plans include 345 KV lines from Tuco, Texas to Woodward, Okla.

In addition to utility-sponsored transmission expansion, several large "overlay" transmission projects have been proposed to construct 765 KV transmission facilities through the service areas of the utility subsidiaries. It is not certain if or when specific overlay projects may be constructed and placed in service.

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 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. New Mexico repealed its legislation related to retail electric utility competition.

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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 2009, FERC adopted rules requiring MISO and SPP to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, NSP-Wisconsin and SPS, respectively, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in its state. See further discussion in Public Utility Regulation below. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or 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.


NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of JurisdictionRetail 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 generating and transmission facilities, and the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see Market Based Rate Rules discussion) and is a transmission-owner member of the MISO RTO.

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

CIP — The CIP invests in programs that help customers save energy. CIP includes a comprehensive list of programs that benefit all customers including Saver's Switch®, energy efficiency rebates and energy audits.

EIR — The EIR recovers the costs of environmental improvements to the A. S. King, High Bridge and Riverside plants, which were renovated under the MERP program.

GAP — The GAP is a surcharge billed to all non-interruptible customers to recover the costs of offering a low-income customer co-pay program designed to reduce natural gas service disconnections.

MCR — The MCR recovers costs related to reducing Mercury emissions at two NSP-Minnesota fossil fuel power plants.

RDF — The RDF allocates money to support development of renewable energy projects research and development of renewable energy technologies.

RES — In 2007, the Minnesota legislature passed new requirements mandating that a certain percent of energy produced by utilities like NSP-Minnesota come from renewable resources. In order to ensure these mandates can be met, the legislature allows utilities to recover the costs of new renewable generation projects to meet the RES in a rider.

SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.

TCR — The TCR recovers costs associated with new investments in the electric transmission system necessary to deliver electric energy to customers.

NSP-Minnesota's retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments 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 approved by the regulators in each jurisdiction.

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The FCAs 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 general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or through rate cases.

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 changed 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 RegulationThe MPUC approved a rate rider to recover prudent costs to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant beginning Jan. 1, 2006. A. S. King, High Bridge and Riverside went into service in July 2007, May 2008 and March 2009, respectively. In December 2009, the MPUC authorized the recovery of approximately $116.7 million in 2010 rates. The ROE for the A. S. King plant, the High Bridge plant and the Riverside plant, is 10.55 percent, 11.22 percent and 10.55 percent, respectively. The MERP projects will be included in rate base in the next general rate case and the projects removed from the rider.


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 2010, assuming normal weather, is listed below.

 
  System Peak Demand (in MW)  
 
  2007   2008   2009   2010 Forecast  

NSP System

    9,427     8,697     8,615     9,280  

The peak demand for the NSP System typically occurs in the summer. The 2009 uninterrupted system peak demand for the NSP System occurred on June 23, 2009.


Energy Sources and Related Transmission Initiatives

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

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

NSP-Minnesota also makes short-term purchases to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.

Purchased Transmission ServicesIn addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.

Excelsior EnergyIn 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. 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 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

In its August 2007 Phase 1 order, the MPUC found, among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the OES and the guidance provided by the order.

In May 2009, the MPUC affirmed its previous order to deny Excelsior Energy's Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility, which closed the docket. In August 2009, Excelsior appealed the MPUC decision to the Minnesota Court of Appeals. The Minnesota Court of Appeals heard arguments on Feb. 23, 2010, and a decision is anticipated in 2010.

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GHG EmissionsThe 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors 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 also 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 provides for certain exemptions.

In November 2008, the MPUC approved NSP-Minnesota's request to include the costs of a natural gas cast iron pipe replacement project in its SEP Rider. The proposed cost recovery was enabled by the 2007 legislation, as the pipe replacement is expected to reduce GHG emissions. NSP-Minnesota expects to recover approximately $1.4 million over the 2009-2013 period, when the project is scheduled to be complete.

2009 Minnesota Legislative SessionThe 2009 Minnesota legislature considered and adopted several measures related to energy policy and regulation, including:

Permitting enhanced recovery for costs associated with the urban central corridor development;

Encouraging the development of solar resources; and

Continued encouragement of DSM.

The legislature considered, but did not adopt, increased taxes on utility property.

Minnesota Resource PlanIn July 2009, the MPUC approved NSP-Minnesota's 2007 resource plan. The plan would reduce CO2 emissions by 22 percent from 2005 by 2020, a 6 million ton reduction. The plan includes the following components:

Energy efficiency savings of 1.15 percent in 2010, 1.2 percent in 2011 and 1.3 percent in 2012;

Install sufficient renewables to meet the Minnesota RES;

Obtain required approvals to extend the life of the Prairie Island nuclear plant and to increase the output at both Prairie Island and Monticello;

Continue ongoing capacity expansion at Sherco Unit 3;

Continue to investigate repowering Black Dog Units 3 and 4, and provide the MPUC with specific plans and timelines for the repowering;

Obtain approval for the 375 MW intermediate and 350 MW diversity exchange with Manitoba Hydro beginning in 2015; and

Continue to ensure sufficient transmission available to deliver generation to load.

Additionally, the MPUC required NSP-Minnesota to consider higher levels of DSM and energy efficiency and provide recommendations in NSP-Minnesota's next resource plan, which is to be filed no later than Aug. 1, 2010.

RESIn 2007, the Minnesota legislature changed the state's renewable energy objective into a standard that requires NSP-Minnesota to generate or cause to be generated electricity from renewable resources equaling:

At least 15 percent of its retail sales by 2010;

18 percent of retail sales by 2012;

25 percent of retail sales by 2016; and

30 percent by 2020.

Of the 30 percent, at least 25 percent must be generated by wind energy conversion systems and the remaining five percent by other eligible energy technology. The law allows for a modification or delay in the implementation of the standard if the implementation would cause significant rate impact, require significant measures to address reliability or raises significant technical issues. All other Minnesota utilities are required to meet a 25 percent RES by 2025. No Minnesota utility has requested a modification or delay of the standard at this time.

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Minnesota Statutes also allow for recovery of eligible renewable energy investments through a cost recovery rider. NSP-Minnesota began recovering eligible investments through this mechanism in 2008.

Wind GenerationNSP-Minnesota is investing approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project. These projects are expected to be operational by the end of 2010 and 2011, respectively. In June 2009, the MPUC approved the Nobles and Merricourt Wind Projects. In August 2009, the NDPSC granted advanced determinations of prudence for the Nobles and Merricourt Wind Projects and a certificate of public convenience and necessity (CPCN) for the Merricourt Wind project.

NSP-Minnesota Transmission CONsIn April 2009, the MPUC granted a CON to construct three 345 KV electric transmission lines as part of the CapX 2020 project. The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion. The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million. These cost estimates will be revised after the regulatory process is completed. The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy. In September 2009, two intervenors appealed the MPUC's CON decisions in the Minnesota Court of Appeals.

As part of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesota and Great River Energy have filed four route permit applications with the MPUC. Route permit applications for the remaining parts of the three lines are expected to be filed in adjoining states in 2010. Three filed route permit applications are now in evidentiary hearing processes before ALJs. The fourth application is expected to be sent to an evidentiary hearing process later in 2010. NSP-Minnesota anticipates the first routing decisions in mid 2010.

As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a CON application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn. The CON application was approved in July 2009. Route hearings are scheduled to begin March 30, 2010, and an MPUC decision is anticipated by the third quarter of 2010. The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by the end of 2011. The estimated cost to NSP-Minnesota is approximately $26 million.

ARCsIn 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state. ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota. The MISO ARC tariff provisions are effective in June 2010. The MPUC has opened an investigation regarding possible operation of ARCs in Minnesota. NSP-Minnesota expects to file requests with the NDPSC and SDPUC by the end of the first quarter of 2010 asking the regulatory agencies to prohibit operations of ARCs in their respective states, and to take action prior to June 2010.

FCA InvestigationIn 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCA for electric utilities in Minnesota. Continued discussions among utilities, the OES, MOAG and business customers regarding appropriate FCA reporting detail and provision of additional information to customers is ongoing.

Mercury Reduction and Emissions Reduction FilingsThe MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants. A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010. Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million from customers through a mercury rider in 2010. On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider.

Nuclear Power Operations and Waste DisposalNSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units. See additional discussion regarding the nuclear generating plants at Note 18 to the consolidated financial statements.

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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. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

LLW Disposal — Federal law places responsibility on each state for disposal of LLW generated within its borders. LLW from NSP-Minnesota's Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah. NSP-Minnesota 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.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of 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 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 17 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 generating plants. At the following dates, casks for storage were either authorized or casks were loaded and stored:

In 2003, the Minnesota legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the Prairie Island nuclear plant and to store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. It is estimated that operation through the end of the current license will require 29 storage casks at Prairie Island.

In October 2006, effective June 2007, the MPUC authorized an on-site storage facility and dry cask storage of 30 casks at Monticello, which will allow the plant to operate to 2030.

In December 2009, the MPUC authorized additional cask storage at Prairie Island to allow operation through 2033 for Unit 1 and 2034 for Unit 2. The MPUC decision is currently stayed to allow the Minnesota legislature the opportunity to review the MPUC decision during the 2010 legislative session. If no action is taken by the Minnesota legislature during the 2010 legislative session the MPUC order will go into effect on June 1, 2010.

As of Dec. 31, 2009, there were 25 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.

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 December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation's spent nuclear fuel. In September 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous conditional approval of the site lease between PFS and the Skull Valley Indian tribe. In July 2007, PFS and the Skull Valley Band filed a lawsuit challenging these two Departments of the Interior actions. The lawsuit remains pending. A judicial appeal of the NRC licensing decision has been held in abeyance pending the outcome of the lawsuit challenging the Department of the Interior decisions. The existence of PFS as a licensed out-of-state storage option remains a credible alternative if PFS and the Skull Valley Band can prevail in the pending litigation and if the federal government fails to make progress with their obligation to take title and remove spent nuclear fuel from Xcel Energy's and other nuclear reactor sites.

Nuclear Plant Power Uprates and Life Extension — NSP-Minnesota is pursuing life extensions and capacity increases of all three of its nuclear units that will total approximately 235 MW, if approved, between 2011 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on the replacement of the original steam generators, currently planned for replacement during the refueling outage in 2013. Capital investments for life cycle management and power uprate activities through 2009 have totaled over approximately $257 million. For the years 2010 through 2015, spending is estimated at over $1.0 billion. See additional discussion in Capital Requirements in Item 7 — Management's Discussion and Analysis.

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In December 2008, the MPUC approved the Monticello CON for approximately 71 MW of power uprates. In 2008, NSP-Minnesota re-submitted its NRC application for the Monticello plant extended power uprate, and the NRC's sufficiency review of the license amendment re-submittal was completed. NSP-Minnesota expects to receive NRC approval and achieve the extended power uprate during 2011. The operating life of the Monticello nuclear plant has already been extended through 2030.

In December 2009, the MPUC approved both the additional dry spent fuel storage capacity to support life extension and the approximately 164 MW of power uprates at Prairie Island Units 1 and 2. If no action is taken by the Minnesota legislature during the 2010 legislative session, the MPUC decision on dry spent fuel storage capacity to support life extension will go into effect on June 1, 2010.

In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively. The PIIC filed contentions in the NRC's license renewal proceeding in August 2008, which was referred to an ASLB for review. The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed. To date, all seven admitted contentions have been resolved and removed from the ASLB docket. Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions. The ASLB has admitted one of the contentions and has not issued a decision on the other three. NSP-Minnesota is challenging the admitted contention, and a decision on whether the other contentions will be accepted will be made in early 2010. If the contentions are not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC's standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.


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    
 
 
  Weighted Average Fuel Cost  
NSP System Generating Plants
  Cost   Percent   Cost   Percent   Cost   Percent  
 

2009

  $ 1.78     57 % $ 0.70     39 % $ 7.36     4 % $ 1.61  
 

2008

    1.73     58     0.56     39     10.09     3     1.55  
 

2007

    1.56     57     0.51     38     7.60     4     1.47  

*
Includes refuse-derived fuel and wood.

See additional discussion of fuel supply and costs under Item 7 — Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis and under Item 1A — Risk Factors.


Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2009 and 2008 were approximately 43 and 49 days usage, respectively. 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's and NSP-Wisconsin's major coal-fired generating plants were approximately 10.2 and 11.0 million tons per year at Dec. 31, 2009 and 2008, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 91 percent of their coal requirements in 2010, 60 percent of their coal requirements in 2011 and 14 percent of their coal requirements in 2012. Any remaining requirements will be filled through a RFP process or through over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2010, 28 percent of their coal requirements in 2011 and 28 percent of their coal requirements 2012. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication for the operation of its nuclear generation plants. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment with multiple producers to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2010, approximately 85 percent of the requirements for 2011 through 2014, and 49 percent of the requirements for 2015 through 2017, with no arrangements for 2018 and beyond. Contracts for additional uranium concentrate supplies are currently in various stages of negotiations that are expected to provide a portion of the remaining open requirements through 2025.

Current contracts for conversion services cover 100 percent of the requirements through 2011 and approximately 70 percent of the requirements from 2012 through 2016, with no arrangements for 2017 and beyond. Contracts for additional conversion services are being evaluated and negotiated to provide a portion of remaining open requirements for 2014 and beyond.

Current enrichment services contracts cover 100 percent of 2010 through 2013 requirements. Contracts for additional enrichment services are being evaluated and negotiated to provide a portion of the remaining open requirements for 2014 and beyond.

Fabrication services for Monticello are covered through 2011. Responses from fuel fabrication vendors to our RFPs for additional supply for Monticello are being reviewed with plans to enter into a contract with one of the vendors in 2010. Prairie Island's fuel fabrication is 100 percent committed through 2014.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Some exposure to price volatility will remain, due to index-based pricing structures on the contracts.

Natural gas — 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 supply, 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, 2009, NSP-Minnesota's commitments related to supply contracts were $53 million and commitments related to transportation and storage contracts were approximately $538 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 JurisdictionRetail rates, services and other aspects of NSP-Wisconsin's operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale the transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see Market Based Rate Rules discussion) and is a transmission-owning member of the MISO RTO.

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.

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Bay Front Biomass GasificationIn December 2009, the PSCW granted NSP-Wisconsin a certificate of authority to install biomass gasification technology at the Bay Front Power Plant in Ashland, Wis. The project will convert a third boiler to biomass gasification technology allowing the plant to use up to 100 percent biomass in all three boilers. The project, estimated to cost $58 million, will require additional biomass receiving and handling facilities at the plant, an external gasifier, minor modifications to the plant's remaining coal-fired boiler and an enhanced air quality control system. The project is expected to improve the environmental performance of the plant and contribute towards state RES in the region. Engineering and design are expected to begin in 2010, and the unit could be operational by late 2012.

NSP-Minnesota also made filings in North Dakota and Minnesota requesting future rate recovery of the portion of the project costs that will be billed to NSP-Minnesota through the Interchange Agreement. Decisions on those filings are currently pending regulatory action before the NDPSC and the MPUC respectively.

Fuel and Purchased Energy Cost Recovery MechanismsNSP-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 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 Fuel Cost Recovery LegislationExisting statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities, but authorize the PSCW to approve a rate increase to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel.

In November 2009, a bill was introduced in the Wisconsin legislature to modify the existing statutes and rules governing electric fuel cost recovery in utility rates. Under the proposed statutes, an electric utility would submit a forward-looking annual fuel cost plan for approval by the PSCW. Once a utility has an approved fuel cost plan, it could then defer any under-collection or over-collection of fuel costs for future rate recovery or refund, providing that the under/over-collection exceeds a symmetrical annual tolerance band established by the PSCW. Approval of a fuel cost plan and any rate adjustment for recovery or refund of deferred costs would be determined by the PSCW after opportunity for a hearing. If passed, the legislation would require the PSCW to promulgate rules to implement the new statutes.

NSP-Wisconsin expects hearings on the legislation to occur in the 2010 session; however, at this time it is uncertain what, if any, additional action the legislature will take with respect to this legislation.

Wisconsin RPS and Energy Efficiency and Conservation GoalsThe Wisconsin legislature has passed an RPS that requires 10 percent of electric sales statewide to 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 12.89 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.

ARCsIn 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Wisconsin, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state. ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Wisconsin. The MISO ARC tariff provisions are effective in June 2010. During 2009, the PSCW and MPSC issued orders temporarily prohibiting ARCs from operating in Wisconsin and Michigan, respectively, pending further regulatory proceedings. NSP-Wisconsin expects the PSCW and MPSC to conduct additional proceedings following the implementation of the MISO ARC tariffs.


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.

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

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

ECA — The ECA recovers fuel and purchase power costs. Short-term sales margins and margins from the sale of SO2 allowances are shared with retail customers through the ECA. The total incentive cannot exceed $11.25 million in any year. For 2009, it included an incentive adjustment to encourage efficient operation of base load coal plants and to encourage cost reductions through purchases of economical short-term energy. Effective Jan. 1, 2010, the incentive adjustment was eliminated from the ECA mechanism. The ECA mechanism is revised quarterly.

PCCA — The PCCA allows for recovery of purchased capacity payments for most power purchase agreements. New rates went into effect Jan. 1, 2010.

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

AQIR — Effective January 2003, the AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area. The CPUC approved PSCo's filing to roll the AQIR into base rates, which was reflected in rates on Jan. 1, 2010.

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

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

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

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

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause accepted for filing by the FERC. PSCo's larger wholesale customers have agreed to pay the full cost of the acquisition of certain non-solar renewable energy purchase and generation costs through a rider and in exchange receive renewable energy credits associated with those resources.

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Performance-Based Regulation Plan (PBRP) and Quality of Service RequirementsPSCo 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 2010, assuming normal weather, is listed below.

 
  System Peak Demand (in MW)  
 
  2007   2008   2009   2010 Forecast  

PSCo

    6,950     6,903     6,258     6,608  

The peak demand for PSCo's system typically occurs in the summer. The 2009 uninterrupted system peak demand for PSCo occurred on Aug. 12, 2009.


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 ServicesIn addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver power and energy to PSCo's customers.

Purchased PowerPSCo has contracts to purchase power from other utilities and independent power producers. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased.

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

PSCo Resource PlanIn September 2008, the CPUC issued its order detailing the amount of resources that will be added, including the following:

Increase in wind portfolio of 850 MW by 2015. PSCo would then have a total of approximately 1,900 MW of wind power resources;

Add up to 250 MW of concentrating solar thermal technology with thermal storage;

Increase customer efficiency and conservation programs with plans to meet the CPUC goals of annual energy sales reductions to approximately 3,669 GWh, that would yield a demand savings in the range of 886 MW to 994 MW by 2020;

Retirement of two older coal-burning plants (two units at Arapahoe and two units at Cameo), replacing the capacity with company owned resources, provided the costs are reasonable; and

Reduce PSCo's CO2 emissions between 10 and 15 percent below 2005 levels and for PSCo to propose additional reductions to achieve a 20 percent reduction by 2020 in its next plan.

PSCo acquired 174 MW of wind resources and 19 MW of central station photovoltaic (PV) solar resources through separate RFPs and those contracts were specifically approved by the CPUC. In January 2009, PSCo issued an all-source RFPs to fill the approved resource plan. Bids were received in April 2009, and PSCo filed its bid evaluation report with the CPUC in August 2009.

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In October 2009, the CPUC approved the acquisitions of the resources identified in the evaluation report. With minor modification, the CPUC adopted PSCo's preferred plan which includes an incremental 900 MW of additional intermittent renewable energy resources (wind and PV solar) and approximately 280 MW of "new technology" renewable energy sources. The CPUC approved the negotiation of purchased power contracts from a pool of PV solar bidders, rather than designating specific bidders. The CPUC approved the selection of about 800 MW of traditional gas-fired resources. The CPUC preferred that PSCo file its next resource plan in the normal course of business in the fall of 2011 rather than making an interim filing in 2010.

RESThe 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 for the years 2011 through 2014;

15 percent of retail sales for the years 2015 through 2019;

20 percent of retail sales by 2020 and after; and

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

The law limits the net incremental retail rate impact from these renewable resource acquisitions as compared to non-renewable resources to 2 percent. The new legislation encourages the CPUC to consider earlier and timely cost-recovery for utility investment in renewable resources, including the use of a forward rider mechanism.

The CPUC approved all material aspects of PSCo's 2009 RES compliance plan in August 2009. The 2010 compliance plan was filed in October 2009.

San Luis Valley-Calumet-Comanche Unit 3 Transmission ProjectPSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a certificate of need and public convenience in May 2009. The project consists of four components of both 230 KV and 345 KV line and substation construction. The line is intended to assist in bringing solar power in the San Luis Valley to load. The line is expected to be placed in-service in 2013 if no significant issues in the siting and permitting of the line are encountered. Several landowners are opposing this transmission line, including two large ranches. Hearings before an ALJ were conducted in February 2010, with a decision pending.


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    
 
 
  Weighted
Average Fuel
Cost
 
PSCo Generating Plants
  Cost   Percent   Cost   Percent  

2009

  $1.52   82 % $3.99   18 % $1.97  

2008

  1.42   84   7.03   16   2.31  

2007

  1.26   84   4.34   16   1.76  

See additional discussion of fuel supply and costs under Item 7 — Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis and under Item 1A — Risks Associated with Our Business.

Fuel Sources

Coal — Coal inventory levels may vary widely among plants. However, PSCo normally maintains approximately 41 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2009 and 2008 were approximately 68 and 32 days usage, respectively, based on the maximum burn rate for all of PSCo's coal-fired plants. PSCo's generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2009 and 2008, PSCo's coal requirements for existing plants were approximately 9.2 million and 11 million tons, respectively.

PSCo has contracted for coal suppliers to supply 82 percent of its coal requirements in 2010, 50 percent of its coal requirements in 2011 and 19 percent of its coal requirements in 2012. Any remaining requirements will be filled through an RFP process or through over-the-counter transactions.

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PSCo has coal transportation contracts that provide for delivery of 95 percent of its coal requirements in 2010, 95 percent of its coal requirements in 2011 and 60 percent of its coal requirements in 2012. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather, and availability of equipment.

Natural gas — PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo's power plants are procured under contracts to provide an adequate supply of fuel. The supply contracts expire in various years from 2010 through 2020. The transportation and storage contracts expire in various years from 2010 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, 2009, PSCo's commitments related to supply contracts were approximately $159 million and transportation and storage contracts were approximately $1.1 billion.


Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. PSCo uses physical and financial instruments to 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 JurisdictionThe 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 original jurisdiction over SPS' rates in those communities. SPS can and does then appeal municipal rate decisions to the PUCT. 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, the transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce.

Fuel, Purchased Energy and Conservation Cost-Recovery MechanismsFuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS' retail electric tariff. The regulations allow retail fuel factors to change up to three times per year.

Because regulations require that actual fuel and purchased energy costs be recovered from ratepayers, there is an accounting of over- or under-recovery of fuel and purchased energy expenses under the fixed factor. Regulations also 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 on a rolling 12-month basis, if this condition is expected to continue.

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

The NMPRC has authorized SPS to continue to use a monthly adjustment factor for a fuel and purchased power cost adjustment clause (FPPCAC) for SPS' New Mexico retail jurisdiction. NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC. In that proceeding, the NMPRC reviews SPS' use of its FPPCAC since the filing of its previous fuel clause continuation filing. SPS' next fuel clause continuation filing is due Aug. 26, 2010.

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

Performance-Based Regulation and Quality of Service RequirementsIn Texas, SPS is subject to a QSP requiring SPS to comply with electric service reliability performance targets. In October 2008, the PUCT staff served SPS with notice that it had initiated an investigation to determine whether SPS is in compliance with the Texas statutes and PUCT rules on reliability and continuity of service.

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Texas EECRF RiderPUCT regulations established the mechanism under which electric utilities may recover costs associated with providing energy efficiency programs. That mechanism, an EECRF rider, must be included in a utility's tariff and may be established in a utility's base rate case or through a separate request seeking to establish an EECRF. In accordance with this rule, SPS has removed its energy efficiency costs from its recent base rate proceeding, and has requested implementation of its EECRF rider to recover the remaining unamortized balance of historic costs and its projected 2008 and 2009 energy efficiency costs. In September 2008, the PUCT concluded that the rule under which the application was filed does not apply to SPS and the energy efficiency costs could be recovered in the pending Texas retail base rate case. SPS reached a negotiated settlement with the parties and included base rate recovery amounts explicitly designated for energy efficiency. In February of 2010, the PUCT issued a proposed rule that would make SPS subject to the same requirements with respect to the EECRF as other utilities in the state.

New Mexico Energy Efficiency Disincentive RulemakingDuring the last legislative session, increased energy efficiency goals and more affirmative disincentive language were adopted. The NMPRC is currently conducting a rulemaking proceeding to update the energy efficiency rule, consistent with the legislative changes.

SPS Participation in the SPP RTOIn October 2007, the NMPRC ordered an investigation of the benefits of SPS' participation in the SPP RTO. The conversion of SPS' retail load to transmission service under the SPP tariff effective Feb. 1, 2010 was mandatory under the SPP membership agreement. In September 2009, the parties filed a stipulation resolving all issues in the proceeding for a five year interim period. On Feb. 2, 2010, the NMPRC approved the settlement authorizing SPS to put its retail load under the SPP OATT effective Jan. 1, 2010.

TUCO to Woodward District Extra High Voltage (EHV) InterchangeThe SPP, as a part of its balance portfolio plan, issued a notice in June 2009 directing SPS to construct a 178 mile 345 KV transmission line between Lubbock, Texas and Woodward, Okla. The estimated investment in the new line is $149 million and will be recovered from SPP members, including SPS, in accordance with the SPP OATT and the retail ratemaking process. A decision is pending.


Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2010, assuming normal weather, is listed below.

 
  System Peak Demand (in MW)  
 
  2007   2008   2009   2010 Forecast  

SPS

    4,731     4,996     5,038     4,945  

The peak demand for the SPS system typically occurs in the summer. The 2009 uninterrupted system peak demand for SPS occurred on July 14, 2009. Peak demand in 2010 is expected to decrease due to the expiration of a wholesale contract with El Paso Electric.


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 PowerSPS has contracts to purchase power from other utilities and independent power producers. 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. SPS also makes short-term purchases to comply with minimum availability requirements, and to obtain energy at a lower cost.


SPS Resource Planning

Integrated Resource Planning — SPS's IRP in New Mexico was approved in August 2009 under the NMPRC's rule.

Renewable Energy Portfolio Plan — SPS is required to develop and implement a renewable portfolio plan in New Mexico in which six percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2010. The renewable standard increases to ten percent in 2011. SPS primarily fulfills its renewable portfolio requirements through purchased wind energy generation in eastern New Mexico. In October 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 with the provision that SPS will make-up any shortfall of solar energy requirement for 2011 during 2012 through 2014. SPS has executed certain commercial agreements for solar energy purchased power and SPS sought regulatory approval in January 2010.

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Pending Resource Solicitations — SPS released four RFP's during 2008, targeting capacity and energy resources as follows:

up to 200 MW under terms of 3 to 8 years with deliveries beginning either June 2010 or June 2011;

up to 250 MW of wind resources located in Texas portion of the SPS balancing authority;

up to 600 MW of dispatchable resources with terms of up to 20 years and deliveries beginning either June 2012 or June 2013; and

a non-wind RFP for renewable energy in New Mexico consisting of solar and biomass technologies.

SPS awarded a winning bid to Sun Edison for 50 MW of photovoltaic solar to be installed at five sites (10 MW each) in New Mexico and signed contracts in 2009, and a request for approval was filed in January 2010.

Purchased Transmission ServicesSPS 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.


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    
 
 
  Weighted
Average Fuel
Cost
 
SPS Generating Plants
  Cost   Percent   Cost   Percent  

2009

  $1.74   73 % $3.80   27 % $2.30  

2008

  1.86   71   8.41   29   3.78  

2007

  1.64   67   6.45   33   3.22  

See additional discussion of fuel supply and costs under Item 7 — Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis and under Item 1A — Risks Associated with Our Business.

Fuel Sources

Coal — 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 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, 2009, coal inventories at the Harrington and Tolk sites were approximately 46 and 54 days supply, respectively. TUCO has coal agreements to supply 89 percent of SPS' coal requirements in 2010, 37 percent of SPS' coal requirements in 2011, and 35 percent of SPS' coal requirements in 2012, which are sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

Natural gas — SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas for SPS' power plants is procured under contracts to provide an adequate supply of fuel. The supply contracts expire in 2010. The transportation and storage contracts expire in various years from 2010 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, 2009, SPS' commitments related to supply contracts were approximately $47 million and transportation and storage contracts were approximately $253 million.


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.

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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, including enforcement of NERC mandatory electric reliability standards. 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 16 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 required the FERC to adopt new regulations to implement various aspects of the Energy Act. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

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 new FERC rules and regulations as they become effective.

Electric Reliability Standards Compliance

Compliance Audits

On Oct. 31, 2008, the Western Electricity Coordinating Council (WECC) auditors issued their final audit report on PSCo's compliance with electric reliability standards. The report found a possible violation of one reliability standard related to relay maintenance.

In 2008, the NSP System, PSCo and SPS filed self-reports with the Midwest Reliability Organization (MRO), WECC and SPP regional entities, respectively, relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection standards. In 2009, the NSP System, PSCo, and SPS each reached agreement with the relevant regional entity that would resolve the PSCo open 2008 audit finding and the 2008 self reports by payment of a non-material penalty. Xcel Energy is in the process of developing definitive settlement agreements with the regional entities. These settlement agreements will be subject to NERC and FERC approval.

NERC Compliance Investigation

On Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection, as a result of a series of transmission line outages. In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada. The initial transmission line outages occurred on the NSP System. In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the September 2007 event. Because the event affected more than one region, the NERC took over the investigation. In January 2010, the NERC issued a preliminary report alleging the NSP System violated certain NERC reliability standards. The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review. Xcel Energy disagrees with the many aspects of the preliminary report and filed its response with NERC on Feb. 19, 2010. The final outcome of the NERC compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

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

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Centralized Regional Wholesale MarketsThe FERC rules allow RTOs to operate centralized regional wholesale energy markets. In April 2005, MISO began operation of a Day 2 regional day-ahead and real time wholesale energy market. The Day 2 market is designed to provide more efficient generation dispatch over the 15 state MISO region, including the NSP System. In 2007, SPP began operation of an energy imbalance service (EIS) market, which provides a more limited wholesale energy balancing market for the region that includes the SPS system.

In January 2009, MISO began ASM operations, which 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.

Market Based Rate RulesEach of the Xcel Energy utility subsidiaries has been granted market-based rate authority. Under market based rate rules, the NSP System was reauthorized to sell at market-based rates in June 2009. SPS filed a request for market-based rate reauthorization with the FERC in July 2009. That request is pending FERC action. PSCo will be required to file for such reauthorization in June 2010. Presently the Xcel Energy utility subsidiaries may not sell power at market-based rates within the PSCo and SPS balancing authorities, where they have been found to have market power under the FERC's applicable analysis. Both PSCo and SPS have cost-based coordination tariffs that they may use to make sales in their balancing authorities.

FERC Tie Line InvestigationIn October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of use of network transmission service across the Lamar Tie Line, a transmission facility that connects PSCo and SPS. In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies and rules and approved tariffs. The report represents the preliminary conclusions of the DOI and is subject to additional procedures. The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report. Xcel Energy disagrees with the preliminary report. Xcel Energy continues to cooperate with the DOI investigation. Given the preliminary nature of this matter, Xcel Energy is unable to determine if the resolution of this matter will have a material adverse impact on operations, cash flows or financial condition.

MISO Long-Term Transmission PricingTransmission service rates in the MISO region have historically used a rate design in which the transmission cost depends on the location of the load being served, which is referred to as license plate rates. Costs of existing transmission facilities are thus not regionalized. MISO has implemented several changes regarding the allocation of costs for new transmission facilities. In 2006 and 2007, the FERC issued orders accepting the so-called RECB tariff, which provide a 20 percent limitation on the portion of transmission expansion costs that may be regionalized and recovered from all loads in the 15 state MISO region.

In 2007, AEP filed a proposal that would regionalize certain costs of the existing AEP system over the MISO and PJM RTO regions. The AEP proposal would shift several million dollars in transmission costs annually to the NSP System. The impact of the AEP proposal on transmission cost allocation in MISO is uncertain.

In July 2009, MISO filed a proposed change to the RECB tariff with the FERC to address concerns regarding allocation of costs associated with new transmission required to deliver new wind generation. This tariff would regionalize 10 percent of the cost of new 345 KV transmission facilities associated with new generation interconnections across transmission users in MISO, with the interconnecting generator paying the remaining 90 percent of the costs. The generator is required to fund 100 percent of the costs for facilities less than 345 KV. The FERC approved the tariff change in October 2009, subject to a permanent replacement cost allocation tariff to be filed with the FERC in July 2010. The uncertainty surrounding allocation of costs associated with wind generation interconnection could affect the timing or location of such interconnections, which could affect near term NSP System transmission investment needs.

SPP Transmission Cost RecoveryThe SPP transmission tariff currently establishes the mechanism for recovering costs associated with base plan transmission projects, which are transmission projects required to maintain reliability, and for balanced portfolio transmission projects that promote economic expansion of the SPP grid. Currently, for base plan transmission projects, one-third of the costs are collected on an SPP region-wide basis and the remaining two-thirds are recovered from individual pricing zone(s) in SPP using a power flow analysis. For balanced portfolio projects, 100 percent of the costs are recovered on an SPP region-wide basis. SPP is currently re-evaluating this methodology, and the SPP board of directors has preliminarily approved a highway/byway funding approach that would allocate costs as follows:

For projects rated at a voltage level less than 100 KV, all costs would be recovered from the pricing zone of the project;

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For projects rated at a voltage level between 100 KV and 300 KV, one-third of the costs would be recovered on an SPP region-wide basis and two-thirds would be recovered from the pricing zone of the project; and

For projects rated at a voltage level greater than 300 KV, 100 percent of costs would be recovered on an SPP region-wide basis.

The details of the application of the highway/byway funding approach are still under development in SPP and any methodology would still be subject to FERC approval. The uncertainty surrounding allocation of transmission costs in SPP could affect the timing or location of transmission additions as well as near-term SPS transmission investment.

FERC Audit of Wholesale FCAIn October 2009, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division began an audit of compliance with the FERC's accounting and reporting regulations related to the calculation of the NSP-Minnesota and NSP-Wisconsin wholesale FCA for the period commencing Jan. 1, 2008. The audit is a periodic financial audit, and Xcel Energy is fully cooperating with the audit.

Xcel Energy Electric Operating Statistics

 
  Year Ended Dec. 31,  
 
  2009   2008   2007  

Electric sales (millions of Kwh)

                   

Residential

    24,039     24,448     24,866  

Commercial and industrial

    61,255     63,511     62,396  

Public authorities and other

    1,079     1,079     1,087  
               
 

Total retail

    86,373     89,038     88,349  

Sales for resale

    21,588     23,454     24,202  
               
 

Total energy sold

    107,961     112,492     112,551  
               

Number of customers at end of period

                   

Residential

    2,905,105     2,891,320     2,859,262  

Commercial and industrial

    415,703     411,935     408,366  

Public authorities and other

    71,677     71,403     71,726  
               
 

Total retail

    3,392,485     3,374,658     3,339,354  

Wholesale

    101     114     129  
               
 

Total customers

    3,392,586     3,374,772     3,339,483  
               

Electric revenues (thousands of dollars)

                   

Residential

  $ 2,355,138   $ 2,458,105   $ 2,281,354  

Commercial and industrial

    4,071,707     4,625,581     4,099,017  

Public authorities and other

    116,933     127,757     118,024  
               
 

Total retail

    6,543,778     7,211,443     6,498,395  

Wholesale

    886,417     1,266,256     1,180,728  

Other electric revenues

    274,528     205,294     168,869  
               
 

Total electric revenues

  $ 7,704,723   $ 8,682,993   $ 7,847,992  
               

Kwh sales per retail customer

    25,460     26,384     26,457  

Revenue per retail customer

    $1,929     $2,137     $1,946  

Residential revenue per Kwh

    9.80 ¢   10.05 ¢   9.17 ¢

Commercial and industrial revenue per Kwh

    6.65     7.28     6.57  

Wholesale revenue per Kwh

    4.11     5.40     4.88  

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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 natural gas market prices and the continued trend of declining use per residential customer, as well as small commercial and industrial customers (C&I), as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 1999 to 2009, average annual sales to the typical residential customer declined from 99 MMBtu per year to 81 MMBtu per year and to a typical small C&I customer declined from 472 MMBtu per year to 393 MMBtu per year, on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.


NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of JurisdictionRetail 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. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.

Purchased Gas and Conservation Cost-Recovery MechanismsNSP-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 cost revenues 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 in the state of Minnesota. These costs are recovered from Minnesota customers through an annual cost-recovery mechanism for natural gas conservation and energy management program expenditures. This law will change to an energy savings-based requirement beginning in 2010, and the costs of conservation improvement programs will continue to be recoverable in Minnesota 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 720,983 MMBtu for 2009, which occurred on Jan. 15, 2009.

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 transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 589,492 MMBtu per day. In addition, NSP-Minnesota 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 32 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 32 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 2008-2009 and 2009-2010 entitlement levels are pending MPUC action.

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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:

2009

  $ 5.78  

2008

    8.41  

2007

    7.67  

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 2010 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, 2009, NSP-Minnesota was committed to approximately $637 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 31 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 Item 7 — Management's Discussion and Analysis.


NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of JurisdictionNSP-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. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.

Natural Gas Cost-Recovery MechanismsNSP-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 147,362 MMBtu for 2009, which occurred on Jan. 15, 2009.

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 transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 135,633 MMBtu per 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 38 percent of peak day firm requirements of NSP-Wisconsin.

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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 2009-2010 supply plan was approved by the PSCW in October 2009.


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:

2009

  $ 5.85  

2008

    8.54  

2007

    7.56  

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 2010 through 2029.

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, 2009, NSP-Wisconsin was committed to approximately $126 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 13 domestic suppliers 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 Item 7 — Management's Discussion and Analysis.


PSCo

Public Utility Regulation

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

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

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

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

Performance-Based Regulation and Quality of Service RequirementsThe CPUC established a combined electric and natural gas QSP. See further discussion under Item 1 — Electric Utility Operations.

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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 1,897,604 MMBtu. In addition, firm transportation customers hold 574,910 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,472,514 MMBtu per day. The maximum daily deliveries for PSCo in 2009 for firm and interruptible services were 1,873,412 MMBtu on Dec. 8, 2009.

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 transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,829,862 MMBtu per day, which includes 834,277 MMBtu of supplies held under third-party underground storage agreements. During 2009, a capacity release contract of 30,000 MMBtu per day of firm pipeline capacity expired, and another 33,850 MMBtu per day was released to PSCo electric operations, resulting in a net reduction of 63,850 MMBtu per day in pipeline capacity. Also during 2009, 165,521 MMBtu of storage capacity was converted to firm transportation with balancing service attached. In addition, PSCo operates three company-owned underground storage facilities, which provide about 41,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo's city gate meter stations and a small amount is received directly from wellhead sources.

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


Natural Gas Supply and Costs

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

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

2009

  $ 5.13  

2008

    7.04  

2007

    5.87  

PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, PSCo was committed to approximately $1.5 billion in such obligations under these contracts, which expire in various years from 2010 through 2029.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2009, PSCo purchased natural gas from approximately 38 suppliers.

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

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Xcel Energy Natural Gas Operating Statistics

 
  Year Ended Dec. 31,  
 
  2009   2008   2007  

Natural gas deliveries (thousands of MMBtu)

                   

Residential

    141,719     145,615     138,198  

Commercial and industrial

    88,943     92,682     88,668  
               
 

Total retail

    230,662     238,297     226,866  

Transportation and other

    126,993     133,207     133,851  
               
 

Total deliveries

    357,655     371,504     360,717  
               

Number of customers at end of period

                   

Residential

    1,723,419     1,712,835     1,688,994  

Commercial and industrial

    152,312     151,731     149,557  
               
 

Total retail

    1,875,731     1,864,566     1,838,551  

Transportation and other

    4,826     4,350     4,146  
               
 

Total customers

    1,880,557     1,868,916     1,842,697  
               

Natural gas revenues (thousands of dollars)

                   

Residential

  $ 1,159,079   $ 1,496,772   $ 1,295,095  

Commercial and industrial

    631,728     872,224     738,035  
               
 

Total retail

    1,790,807     2,368,996     2,033,130  

Transportation and other

    74,896     73,992     78,602  
               
 

Total natural gas revenues

  $ 1,865,703   $ 2,442,988   $ 2,111,732  
               

MMBtu sales per retail customer

    122.97     127.80     123.39  

Revenue per retail customer

    $955     $1,271     $1,106  

Residential revenue per MMBtu

    8.18 ¢   10.28 ¢   9.37 ¢

Commercial and industrial revenue per MMBtu

    7.10     9.41     8.32  

Transportation and other revenue per MMBtu

    0.59     0.56     0.59  


ENVIRONMENTAL MATTERS

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. Xcel Energy 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 17 and 18 to the consolidated financial statements and Environmental Matters in Item 7 — Management's Discussion and Analysis.


CAPITAL SPENDING AND FINANCING

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

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EMPLOYEES

The number of full-time Xcel Energy employees at Dec. 31, 2009 and 2008, is presented in the table below. Of the full-time employees listed below, 5,665, or 50 percent, and 5,645, or 50 percent, respectively, are covered under collective bargaining agreements. See Note 11 to the consolidated financial statements for further discussion of the bargaining agreements.

 
  2009   2008  

NSP-Minnesota

    3,763     3,637  

NSP-Wisconsin

    561     546  

PSCo

    2,791     2,772  

SPS

    1,186     1,191  

Xcel Energy Services Inc

    3,050     3,077  
           

Total

    11,351     11,223  
           


EXECUTIVE OFFICERS

Richard C. Kelly, 63, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present. Previously, President, Xcel Energy Inc., October 2003 to August 2009; 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 Inc., August 2000 to August 2002.

Michael C. Connelly, 48, Vice President and General Counsel, Xcel Energy Inc., June 2007 to present. Previously, Vice President of Human Resources, Xcel Energy Inc., November 2005 to June 2007; Vice President and Deputy General Counsel, Xcel Energy Inc., January 2003 to November 2005 and Deputy General Counsel, Xcel Energy Inc., August 2000 to January 2003.

David L. Eves, 51, Chief Executive Officer, PSCo, December 2009 to present; President and Director, PSCo, November 2009 to present. Previously, Chief Operating Officer, PSCo, November 2009 to December 2009; President and Director, SPS, December 2006 to November 2009; Chief Executive Officer, SPS, August 2006 to November 2009; Vice President of Resource Planning and Acquisition, Xcel Energy Inc., November 2002 to July 2006 and Managing Director, Resource Planning and Acquisition, Xcel Energy Inc., August 2000 to November 2002.

Benjamin G.S. Fowke, III, 51, President and Chief Operating Officer, Xcel Energy Inc., August 2009 to present. Previously Executive Vice President, Xcel Energy Inc., December 2008 to August 2009; Chief Financial Officer, Xcel Energy Inc., October 2003 to August 2009; Vice President, Xcel Energy Inc., November 2002 to December 2008; Treasurer, Xcel Energy Inc., October 2003 to May 2004 and Vice President and Chief Financial Officer, Energy Markets Business Unit, Xcel Energy Inc., August 2000 to November 2002.

Cathy J. Hart, 60, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, Xcel Energy Inc., November 2005 to present.

C. Riley Hill, 50, President, Director and Chief Executive Officer, SPS, November 2009 to present. Previously, Vice President and Chief Operating Officer, SPS, July 2009 to November 2009; Regional Vice President, Xcel Energy Services Inc., November 2007 to July 2009; Vice President, Construction, Operations and Maintenance, PSCo, February 2006 to November 2007 and Director Design and Construction, PSCo, March 2004 to February 2006.

Teresa S. Madden, 53, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance, Customer and Field Operations Business Unit, Xcel Energy Inc., 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.

Marvin E. McDaniel, 49, Vice President and Chief Administrative Officer, Xcel Energy Services Inc., August, 2009 to present and Vice President, Talent and Technology Business Areas, Xcel Energy Inc., August 2009 to present. Previously, Vice President, Human Resources, July 2007 to August 2009; Vice President and Assistant Controller, March 2005 to June 2007, Xcel Energy Services Inc. and Vice President and Controller Energy Markets Business Unit, Xcel Energy Services Inc., February 2004 to February 2005.

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Judy M. Poferl, 49, President, Director and Chief Executive Officer, NSP-Minnesota, August 2009 to present. Previously, Regional Vice President, September 2008 to August 2009; Managing Director, Government and Regulatory Affairs, November 2007 to September 2008 and Director, Regulatory Administration, August 2000 to November 2007.

David M. Sparby, 55, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2009 to present. Previously President, Director and Chief Executive Officer, NSP-Minnesota, August 2008 to August 2009; Executive Vice President and Director, Acting President and Chief Executive Officer, NSP-Minnesota, January 2007 to August 2008 and Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., September 2000 to January 2007.

Michael L. Swenson, 59, 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.

George E. Tyson II, 44, Vice President and Treasurer, Xcel Energy Inc., May 2004 to present. Previously, Managing Director and Assistant Treasurer, Xcel Energy Inc., July 2003 to May 2004; Director of Origination, Energy Markets Business Unit, Xcel Energy Inc., May 2002 to July 2003 and Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

David M. Wilks, 63, 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.

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Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy's risk management process is to understand and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable. Our risk management process has three parts: identification and analysis, management and mitigation, and communication and disclosure. Xcel Energy management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability.

Management broadly considers our business, the utility industry, the domestic and global economy, and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process, and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing Xcel Energy's strategy. At the same time, the business planning process identifies areas where a business area may take inappropriate risk to meet goals.

The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy's strategy. The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management. At a threshold level, Xcel Energy has developed a robust compliance program and promotes a culture of compliance, which mitigates risk. In addition to the code of conduct, Xcel Energy has a robust compliance program, including policies, training and reporting options.

Building on the culture of compliance, Xcel Energy manages and mitigates risks through formal structures and groups, including management councils, risk committees, and the services of corporate areas such as internal audit, the corporate controller and legal services. While Xcel Energy has developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

Xcel Energy confronts legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for Xcel Energy's products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy's senior management.

Management provides information to the Board in presentations and communications over the course of the Board calendar. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy's strategy.

The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and Xcel Energy's management and mitigation of the risk. The Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy.


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 we operate our utility subsidiaries 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, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

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The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. 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 costs 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 costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all 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 debt payments and the payment of 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. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor's calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor's methodology. Therefore, 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 rate debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

We are subject to capital market risk.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, such as the collapse in the U. S. sub-prime mortgage market and subsequent broad financial market stress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

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

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One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. Additional margin requirements could impact our liquidity.

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

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

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

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

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. The impact of these cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2009, these sites included:

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

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

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

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

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

There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. 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 our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

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 and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011. We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 17, Commitments and Contingent Liabilities, in our notes to the consolidated financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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

For further discussion, see Management's Discussion and Analysis and Note 17 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 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 NRC safety requirements could necessitate substantial capital expenditures at NSP-Minnesota's nuclear plants. In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

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 with respect to energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, and may impact customers' ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. See credit risk section for more related information.

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

Our utility operations are subject to long-term planning risks.

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

Our operations could be impacted by war, acts of terrorism, 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 power plants under the NRC's design basis threat requirements, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

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

The term business continuity refers to the ability of an entity to maintain day-to-day operations in response to unforeseen events. While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations. The company's response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm's on going business operations.

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

We are subject to information security risks.

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

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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.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC's civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future.

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.

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

We are a holding company and 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 assets. Also, 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, our ability to pay dividends on our common stock and preferred stock or otherwise meet our financial obligations could be adversely affected.

Item 1B — Unresolved Staff Comments

None.

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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 2009 Net
Dependable
Capability (MW)
 

Steam:

               

Sherburne-Becker, Minn.

               
 

Unit 1

  Coal   1976     697  
 

Unit 2

  Coal   1977     697  
 

Unit 3

  Coal   1987     521 (a)

Prairie Island-Welch, Minn.

               
 

Unit 1

  Nuclear   1973     551  
 

Unit 2

  Nuclear   1974     545  

Monticello-Monticello, Minn

  Nuclear   1971     572  

King-Bayport, Minn

  Coal   1968     510  

Black Dog-Burnsville, Minn.

               
 

2 Units

  Coal/Natural Gas   1955-1960     282  
 

2 Units

  Natural Gas   1987-2002     298  

Riverside-Minneapolis, Minn.,
3 Units

  Natural Gas   2009     511  

Combustion Turbine:

               

Angus Anson-Sioux Falls, S.D.,
3 Units

  Natural Gas   1994-2005     384  

High Bridge-St. Paul, Minn.,
3 Units

  Natural Gas   2008     566  

Inver Hills-Inver Grove Heights, Minn.,
6 Units

  Natural Gas   1972     350  

Blue Lake-Shakopee, Minn.,
6 Units

  Natural Gas   1974-2005     490  

Various locations,
23 Units

  Various   Various     181  

Wind:

               

Grand Meadow-Mower County, Minn. 

  Wind   2008     101 (b)
               

      Total     7,256  
               

(a)
Based on NSP-Minnesota's ownership of 59 percent.
(b)
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.
Therefore, the on-demand net maximum capacity is zero.

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NSP-Wisconsin

Station, City and Unit
  Fuel   Installed   Summer 2009 Net
Dependable
Capability (MW)
 

Steam:

               

Bay Front-Ashland, Wis.,

  Coal/Wood/Natural Gas   1948-1956     73  
 

3 Units

               

French Island-La Crosse, Wis.,

  Wood/RDF(a)   1940-1948     29  
 

2 Units

               

Combustion Turbine:

               

Flambeau Station-Park Falls, Wis

  Natural Gas   1969     13  

Wheaton-Eau Claire, Wis.,

               
 

6 Units

  Natural Gas   1973     353  

French Island-La Crosse, Wis.,

               
 

2 Units

  Natural Gas   1974     147  

Hydro:

               
 

62 Units

      Various     258  
               

      Total     873  
               

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


PSCo

Station, City and Unit
  Fuel   Installed   Summer 2009 Net
Dependable
Capability (MW)
 

Steam:

               

Arapahoe-Denver, Colo.,

               
 

2 Units

  Coal   1951-1955     153  

Cameo-Grand Junction, Colo.,

               
 

2 Units

  Coal   1957-1960     73  

Cherokee-Denver, Colo.,

               
 

4 Units

  Coal   1957-1968     717  

Comanche-Pueblo, Colo.,

               
 

2 Units

  Coal   1973-1975     660 (a)

Craig-Craig, Colo.,

               
 

2 Units

  Coal   1979-1980     83 (b)

Hayden-Hayden, Colo.,

               
 

2 Units

  Coal   1965-1976     238 (c)

Pawnee-Brush, Colo

  Coal   1981     505  

Valmont-Boulder, Colo

  Coal   1964     186  

Zuni-Denver, Colo.,

               
 

2 Units

  Coal   1948-1954     91  

Combustion Turbine:

               

Fort St. Vrain-Platteville, Colo.,

               
 

6 Units

  Natural Gas   1972-2009     969  

Various Locations,

               
 

6 Units

  Natural Gas   Various     174  

Hydro:

               

Cabin Creek-Georgetown, Colo.

               

Pumped Storage

               
 

2 Units

      1967     210  

Various Locations,

               
 

12 Units

      Various     32  

Wind:

               

Ponnequin-Weld County, Colo

      1999-2001     25 (d)

Diesel:

               

Cherokee-Denver, Colo.,

               
 

2 Units

  Diesel   1967     6  
               

      Total     4,122  
               

(a)
Construction of Comanche Unit 3, a 750 MW coal-fired unit, is expected to be completed in the first quarter of 2010.
PSCo will own 500 MW of the completed unit.
(b)
Based on PSCo's ownership interest of 9.7 percent.
(c)
Based on PSCo's ownership interest of 75.5 percent of Unit 1 and 37.4 percent of Unit 2.
(d)
Amount represents nameplate rating capacity.

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SPS

Station, City and Unit
  Fuel   Installed   Summer 2009 Net
Dependable
Capability (MW)
 

Steam:

               

Harrington-Amarillo, Texas,

               
 

3 Units

  Coal   1976-1980     1,041  

Tolk-Muleshoe, Texas,

               
 

2 Units

  Coal   1982-1985     1,080  

Jones-Lubbock, Texas,

               
 

2 Units

  Natural Gas   1971-1974     486  

Plant X-Earth, Texas,

               
 

4 Units

  Natural Gas   1952-1964     442  

Nichols-Amarillo, Texas,

               
 

3 Units

  Natural Gas   1960-1968     457  

Cunningham-Hobbs, N.M.,

               
 

2 Units

  Natural Gas   1957-1965     267  

Maddox-Hobbs, N.M

  Natural Gas   1967     118  

Moore County-Amarillo, Texas

  Natural Gas   1954     48  

Combustion Turbine:

               

Carlsbad-Carlsbad, N.M

  Natural Gas   1968     11  

Maddox-Hobbs, N.M

  Natural Gas   1963-1976     60  

Riverview-Electric City, Texas

  Natural Gas   1973     23  

Cunningham-Hobbs, N.M.,

               
 

2 Units

  Natural Gas   1998     218  

Diesel:

               

Tucumcari, N.M.,

               
 

2 Units

      1976-1979      
               

      Total     4,251  
               

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:

Conductor Miles
  NSP-Minnesota   NSP-Wisconsin   PSCo   SPS  

500 KV

  2,917        

345 KV

  6,385   1,152   959   6,800  

230 KV

  1,801     11,505   9,429  

161 KV

  428   1,474      

138 KV

      92    

115 KV

  7,103   1,761   4,842   11,034  

Less than 115 KV

  82,782   31,956   72,980   23,403  

Electric utility transmission and distribution substations at Dec. 31, 2009:

 
  NSP-Minnesota   NSP-Wisconsin   PSCo   SPS  

Quantity

  375   203   221   437  

Natural gas utility mains at Dec. 31, 2009:

Miles
  NSP-Minnesota   NSP-Wisconsin   PSCo   WGI  

Transmission

  135     2,301   12  

Distribution

  9,586   2,202   21,242    

Item 3 — Legal Proceedings

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

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Additional Information

For a discussion of legal claims and environmental proceedings, see Note 17 to the consolidated financial statements. For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments, Item 7 — Management's Discussion and Analysis and Note 16 to the consolidated financial statements.

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

No issues were submitted for a vote during the fourth quarter of 2009.


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 2009 and 2008 and the dividends declared per share during those quarters.

 
  High   Low   Dividends  

2009
                   

First quarter

  $ 19.13   $ 16.01   $ 0.2375  

Second quarter

    18.98     16.83     0.2450  

Third quarter

    20.29     17.44     0.2450  

Fourth quarter

    21.94     18.53     0.2450  

2008
                   

First quarter

  $ 22.90   $ 19.39   $ 0.2300  

Second quarter

    21.73     19.67     0.2375  

Third quarter

    22.39     19.40     0.2375  

Fourth quarter

    20.21     15.32     0.2375  

Book value per share at Dec. 31, 2009, was $15.92. The number of common shareholders of record as of Dec. 31, 2009 was approximately 83,222. 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 (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends. For further discussion of Xcel Energy's dividend policy, see Item 7 — Management's Discussion and Analysis, Liquidity and Capital Resources.

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The following compares our cumulative TSR on common stock with the cumulative total return of the EEI Investor-Owned Electrics Index and the Standard & Poor's 500 Composite Stock Price Index over the last five fiscal years (assuming a $100 investment in each vehicle on Dec. 31, 2004, and the reinvestment of all dividends).

The EEI Investor-Owned Electrics Index currently includes 58 companies and is a broad measure of industry performance.

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

GRAPHIC


*
$100 invested on Dec. 31, 2004 in stock and index — including reinvestment of dividends. Fiscal years ending Dec. 31.

 
  2004   2005   2006   2007   2008   2009  

Xcel Energy

  $ 100   $ 106   $ 139   $ 141   $ 122   $ 147  

EEI Investor-Owned Electrics

    100     116     140     163     121     134  

S&P 500

    100     105     121     128     81     102  

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

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Item 6 — Selected Financial Data

 
  2009   2008   2007   2006   2005  
 
  (Millions of Dollars, Except Share and Per Share Data)
 

Operating revenues

  $ 9,644   $ 11,203   $ 10,034   $ 9,840   $ 9,625  

Operating expenses

    8,176     9,812     8,683     8,663     8,533  

Income from continuing operations

    686     646     576     569     499  

Net income

    681     646     577     572     513  

Earnings available to common shareholders

    677     641     573     568     509  

Weighted average common shares outstanding:

                               
 

Basic

    456,433     437,054     416,139     405,689     402,330  
 

Diluted

    457,139     441,813     433,131     429,605     425,671  

Earnings per share from continuing operations:

                               
 

Basic

  $ 1.49   $ 1.47   $ 1.38   $ 1.39   $ 1.23  
 

Diluted

    1.49     1.46     1.35     1.35     1.20  

Earnings per share:

                               
 

Basic

    1.48     1.47     1.38     1.40     1.26  
 

Diluted

    1.48     1.46     1.35     1.36     1.23  

Dividends declared per common share

    0.97     0.94     0.91     0.88     0.85  

Total assets

    25,488     24,958     23,185     21,958     21,505  

Long-term debt

    7,889     7,732     6,342     6,450     5,898  

Book value per share

    15.92     15.35     14.70     14.28     13.37  

Return on average common equity

    9.5 %   9.7 %   9.5 %   10.1 %   9.6 %

Ratio of earnings to fixed charges(a)

    2.5     2.5     2.2     2.2     2.1  

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

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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 2009, Xcel Energy's continuing operations included the activity of four 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 joint venture formed with CIG to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, 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 4 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.

Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of 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; environmental laws and regulations, 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, 2009 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2009.


Management's Strategic Plans

Xcel Energy's strategy, called Building the Core, has three primary focuses: environmental leadership, achieving financial objectives and optimizing the management of a portfolio of our operating utilities. In summary, our objective is to provide value to our customers and execute 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

Overview

Xcel Energy has adopted environmental leadership as a primary focus, forming the cornerstone of our strategic initiatives. Xcel Energy believes that our environmental leadership meets customer and policy maker expectations, while appropriately managing long-term customer costs, and, in turn, creating shareholder value.

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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 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 Xcel Energy's capital investments, Xcel Energy 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, establishes environmental performance goals and 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 goals, which include the goal of carbon reduction, are incorporated into officer and employee job responsibilities and compensation.

Current Initiatives

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 assure compliance with state initiatives, appropriately manage long-term customer costs and, where appropriate, provide growth opportunities. These initiatives include the following:

Xcel Energy is the nation's largest utility wind energy provider and the nation's fifth largest solar 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 RESs in the states in which Xcel Energy operates. These standards provide for favorable cost-recovery mechanisms and investment opportunities in order to allow Xcel Energy to meet the requirements.

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 allow for a construction work in process return and an incentive based ROE mechanism.

Xcel Energy plans to construct one of the largest biomass generating plants in the Midwest. Xcel Energy has proposed installing technology at the Bay Front Generating Station in Ashland, Wis. to allow it to generate electricity from biomass in all three operating units. Xcel Energy currently has 67 MW of biomass generating capacity in Minnesota and Wisconsin.

Xcel Energy has a number of environmental initiatives focused on our customers. Xcel Energy has the largest customer-driven wind program in the nation called WindSource®. In Colorado, Minnesota and New Mexico, Xcel Energy manages a growing customer-sited solar program, known as Solar*Rewards. Xcel Energy also has an increasing portfolio of customer energy efficiency and conservation programs. Xcel Energy is allowed financial performance incentives associated with our programs in Minnesota and Colorado.

Xcel Energy is also working to apply intelligence to its electric grid, creating a smart grid, to provide customers with more choice, reliability and control over their energy use. Xcel Energy has completed the nation's first fully integrated SmartGridCity™ in Boulder, Colo.

Xcel Energy is a leader in promoting new clean energy technologies for the future. Pursuant to state statute, NSP-Minnesota manages a renewable development fund derived from customer renewable energy charges in Minnesota that allows it to promote renewable technology advancement. Xcel Energy has also initiated a study to improve wind forecasting for the industry, allowing for better integration of wind energy, and 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, and has announced plans to acquire significant solar resources in Colorado, including advanced solar technology with thermal storage. Xcel Energy was a founding member of the Solar Technology Acceleration Center in Colorado, which is focused on advancing solar technology in its final stages of development.

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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 has adopted a methodology for calculating CO2 emissions based on the recently issued reporting protocols of The Climate Registry. Xcel Energy is a "founding reporter" under The Climate Registry. As third-party CO2 reporting protocols continue to evolve, Xcel Energy expects additional changes in reporting methodology and reported CO2 emissions. Starting in 2011, Xcel Energy will also report GHG emissions to the EPA under the agency's newly adopted GHG reporting rule.

Based on The Climate Registry's current reporting protocol, Xcel Energy has estimated that its current electric generating portfolio, which includes coal- and gas-fired plants, emitted approximately 60.1 million tons of CO2 in 2009. Xcel Energy has also estimated emissions associated with electricity purchased for resale to Xcel Energy customers from generation facilities owned by third parties. Xcel Energy estimates that these third-party facilities emitted approximately 20.7 million tons of CO2 in 2009. Estimated total CO2 emissions, associated with service to Xcel Energy electricity customers, declined by 5.9 million tons in 2009 compared to 2008, with a combined cumulative reduction of over 39.0 million tons of CO2 since 2003. Xcel Energy anticipates that its ownership share of Comanche Unit 3, a new coal-fired generation project scheduled for completion in early 2010, will result in CO2 emissions of approximately 3.4 million tons of CO2 per year. Comanche Unit 3, an efficient supercritical pulverized coal unit, will provide low-cost, base load power and help maintain a reliable, reasonably priced and environmentally sound electricity supply in Colorado. Operation of Comanche Unit 3 will help support Xcel Energy's efforts to develop renewable energy, retire older, less-efficient resources and take other steps to reduce emissions across its system consistent with state regulatory processes. Xcel Energy plans to implement clean resource development and conservation plans that will result in overall reductions in Xcel Energy's CO2 emissions, both in absolute terms and per Kwh of electricity produced.

State Resource Plans

During 2009, the acquisition component of the overall Colorado resource plan and the Minnesota resource plan were approved substantially as proposed. Both plans, proposed significant new clean energy resources. Under these plans, Xcel Energy would:

Increase overall system wind capacity from approximately 3,000 MW at the end of 2009 to approximately 4,500 to 5,000 MW by 2015;

Add up to 250 MW of concentrating solar thermal technology with storage;

Increase the size of our customer energy efficiency and conservation programs, resulting in a reduction of retail demand;

Retire and replace several existing coal-fired electric generation facilities;

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

Upgrade the 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, the plans would result in a significant reduction in GHG emissions. The most recently approved Minnesota plan is expected to reduce NSP-Minnesota's CO2 emissions by 22 percent below 2005 levels by 2020. The approved Colorado plan is expected to reduce PSCo's CO2 emissions by 10 percent to 15 percent below 2005 levels by 2015 and enables PSCo to propose additional reductions to achieve the 20 percent reduction goal by 2020, currently established by Executive Order.

Our environmental leadership strategy has resulted in numerous environmental awards and recognition. For example, Xcel Energy was named Utility of the Year by the American Wind Energy Association and also received a 2009 Energy Star® partner of the year award from the EPA. Xcel Energy strives to provide the public with detailed information regarding environmental performance and risk, and was recognized on The Carbon Disclosure Project Leadership Index for its high-quality disclosure of climate change risks. 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 GHG regulation on its future resource acquisition plans. Xcel Energy publishes a Corporate Responsibility Report annually, which is available on our website, www.xcelenergy.com. The Corporate Responsibility Report discloses Xcel Energy's environmental, economic and social performance. Xcel Energy also provides detailed information to environmental research and disclosure organizations, such as Trucost, the Carbon Disclosure Project and The Climate Registry.

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Achieving Financial Objectives

Xcel Energy's financial objectives of Building the Core also have 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, 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 Comanche Unit 3 in Colorado. Transmission legislation has been passed in Minnesota, Colorado, Texas and several other jurisdictions where Xcel Energy operates. In addition, various jurisdictions have adopted legislation allowing for rider recovery of investments in renewable energy.

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:

NSP-Minnesota has made, as part of our MERP program, nearly $1 billion of improvements at three Twin Cities coal-fired generating plants, A. S. King, High Bridge and Riverside, to significantly reduce air emissions from those facilities while increasing the amount of electricity they can produce by approximately 300 MW. New state-of-the-art emission control equipment was placed in service for the A. S. King plant in 2007 and the existing High Bridge facility was replaced with a 575 MW natural gas combined-cycle unit that went into service in May 2008. The final phase of the MERP, the new Riverside combined-cycle plant, was placed in service in May 2009.

Invest approximately $1.4 billion for Comanche Unit 3, a project to build a new 750 MW supercritical coal unit in Colorado. The CPUC has approved PSCo sharing one-third ownership of this plant with other parties. Consequently, PSCo's investment in Comanche Unit 3 will be approximately $1 billion. Comanche Unit 3 is expected to achieve commercial operations by the end of the first quarter of 2010.

Invest $156 million for the addition of two gas fired units totaling 300 MW at the PSCo Fort St. Vrain generating facility, located in Colorado. These units went into service in April 2009.

Invest over a $1 billion through 2015 to extend the lives and increase the output of NSP-Minnesota's two nuclear facilities, Monticello and Prairie Island.

Invest approximately $900 million over three years for the 201 MW Nobles Wind project located in southwestern Minnesota Project, and the 150 MW Merricourt Wind project located in southeastern North Dakota, expected to be operational by the end of 2010 and 2011, respectively.

Investment by the CapX 2020 coalition of utilities of approximately $1.7 billion to expand the transmission system in the upper Midwest with major construction targeted to begin in 2010 and ending three to five years later, of which Xcel Energy's share of the investment is expected to be approximately $900 million, depending on the route and configuration approved by the MPUC.

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 annually, on average, approximately 7 percent from 2009 through 2013.

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 and DSM incentives, 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. DSM incentives, which exist in Colorado and Minnesota, allow Xcel Energy to earn from helping our customers reduce energy. The incentive plans are designed to reward Xcel Energy for achieving performance at or above the approved savings goals.

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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. With any strategic plan, there are goals and objectives. Xcel Energy feels the following financial objectives continue to be both realistic and achievable:

A long-term 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. However, our operations are affected by current local, national and worldwide economic conditions. The consequences of the current recession being prolonged 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 impact the financial objectives discussed above.

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 us to 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, such as market branding and environmental policy research. From an organizational perspective, examples of similarities include corporate center services as well as certain operational functions, such as management of the generation fleet, transmission systems, environmental compliance, NERC and FERC compliance and safety program.

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 and 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.

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Results of Operations

The following table summarizes the diluted earnings per share for Xcel Energy:

 
  2009   2008   2007  
 
  Diluted earnings (loss) per share
 

PSCo

  $ 0.72   $ 0.76   $ 0.77  

NSP-Minnesota

    0.64     0.65     0.62  

NSP-Wisconsin

    0.10     0.10     0.09  

SPS

    0.15     0.07     0.07  

Equity earnings of unconsolidated subsidiaries

    0.03     0.01      
               

Regulated utility — continuing operations

    1.64     1.59     1.55  

Holding company and other costs

    (0.14 )   (0.14 )   (0.12 )
               

Ongoing diluted earnings per share

    1.50     1.45     1.43  

PSRI

    (0.01 )   0.01     (0.08 )
               

Earnings per share — continuing operations

    1.49     1.46     1.35  

Loss per share — discontinued operations

    (0.01 )        
               

GAAP diluted earnings per share

  $ 1.48   $ 1.46   $ 1.35  
               

Ongoing earnings exclude the impact related to the COLI program. COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its COLI program. The 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies. The 2007 earnings were affected by the 2007 settlement with the IRS and include associated interest, penalties and tax discussed further at Note 8 — Income Taxes.

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.

2009 Comparison with 2008

PSCoEarnings at PSCo decreased by four cents per share for 2009. The 2009 decrease is largely due to the negative impact of weather and rising costs, partially offset by new electric rates that went into effect in July 2009.

NSP-MinnesotaEarnings at NSP-Minnesota decreased by one cent per share for 2009. The 2009 decrease is mainly due to the negative impact of weather and timing of nuclear outage expenses. The decrease was partially mitigated by a $91 million electric rate increase that went into effect in January 2009.

NSP-WisconsinEarnings at NSP-Wisconsin were flat for 2009. The 2009 earnings reflect increased costs, which were offset by improved fuel recovery and new rates which were effective in January 2009.

SPSEarnings at SPS increased by eight cents per share for 2009. The 2009 increase was primarily due to electric rate increases in Texas (effective in February 2009) and New Mexico (effective in July 2009) and the 2008 resolution of certain fuel cost allocation issues, which were partially offset by higher purchased capacity costs.

Equity Earnings of Unconsolidated SubsidiariesEquity earnings of unconsolidated subsidiaries increased by two cents per share for 2009 due to our investment in WYCO, which owns a natural gas pipeline in Colorado that began operations in late 2008 as well as a gas storage facility that commenced operations in July 2009.

PSRIPSRI is a wholly owned subsidiary of PSCo. During 2007, Xcel Energy resolved a dispute with the IRS regarding its COLI program. The 2009 impact is primarily related to legal costs associated with company claims against the insurance provider and broker of the COLI policies.

Discontinued OperationsLoss from discontinued operations increased by one cent over 2009 primarily related to an increase in tax related expenses and legal accruals for previously divested businesses.

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2008 Comparison with 2007

PSCoEarnings at PSCo decreased by one cent per share for 2008 compared with 2007. The decrease was due to unfavorable weather offset by favorable sales growth and a gas rate increase.

NSP-MinnesotaEarnings at NSP-Minnesota increased by three cents per share for the 2008 compared with 2007. The increase was due to lower interest and non-operating expenses. This was slightly offset by unfavorable weather and purchased capacity costs.

NSP-WisconsinEarnings at NSP-Wisconsin increased by one cent per share 2008 compared with 2007. The increase was primarily due to an electric rate increase in Wisconsin, which was offset by unfavorable weather.

SPSEarnings at SPS were flat for 2008 compared with 2007. SPS experienced increased sales growth, which was offset by higher purchased capacity costs.

Equity Earnings of Unconsolidated SubsidiariesEquity earnings of unconsolidated subsidiaries increased by one cent per share for 2008 compared with 2007. The increase was primarily due to our investment in WYCO, which owns a natural gas pipeline that began operations in late 2008.

The following tables summarize significant components contributing to the changes in the diluted earnings per share compared with same prior periods, which are discussed in more detail later.

 
  Dec. 31,  

2008 GAAP diluted earnings per share

  $ 1.46  

PSRI

    (0.01 )
       

2008 ongoing diluted earnings per share

    1.45  

Components of change — 2009 vs. 2008

       
 

Higher electric margins

    0.44  
 

Lower natural gas margins

    (0.02 )
 

Higher equity earnings of unconsolidated subsidiaries

    0.02  
 

Higher operating and maintenance expenses

    (0.19 )
 

Higher conservation and DSM expenses (generally offset in revenues)

    (0.09 )
 

Lower other income (expense), net

    (0.05 )
 

Higher taxes, other than income taxes

    (0.03 )
 

Dilution from DRIP, benefit plan and the 2008 common equity issuance

    (0.05 )
       

2009 GAAP diluted earnings per share

    1.48  

Loss per share — discontinued operations

    0.01  
       

Earnings per share — continuing operations

    1.49  

PSRI

    0.01  
       

2009 ongoing diluted earnings per share

  $ 1.50  
       

 


 

Dec. 31,

 

2007 GAAP diluted earnings per share

  $ 1.35  

PSRI

    0.08  
       

2007 ongoing diluted earnings per share

    1.43  

Components of change — 2008 vs. 2007

       
 

Higher AFUDC

    0.06  
 

Higher natural gas margins

    0.06  
 

Higher electric margins

    0.03  
 

Lower operating and maintenance expenses

    0.02  
 

Higher financing costs

    (0.05 )
 

Dilution from DRIP, benefit plan and the 2008 common equity issuance

    (0.03 )
 

Higher depreciation and amortization expenses

    (0.03 )
 

Higher conservation and DSM expenses (generally offset in revenues)

    (0.02 )
 

Other, net

    (0.01 )
       

2008 GAAP diluted earnings per share

    1.46  

PSRI

    (0.01 )
       

2008 ongoing diluted earnings per share

  $ 1.45  
       

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The following table provides a reconciliation of GAAP earnings and earnings per share to ongoing earnings and earnings per share for the years ended Dec. 31:

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Ongoing earnings

  $ 690.0   $ 641.1   $ 612.0  

PSRI

    (4.5 )   4.6     (36.1 )
               

Total continuing operations

    685.5     645.7     575.9  

Discontinued operations

    (4.6 )   (0.1 )   1.4  
               

Total GAAP earnings

  $ 680.9   $ 645.6   $ 577.3  
               

 


 

2009

 

2008

 

2007

 
 
  (Dollars per Share)
 

Ongoing earnings

  $ 1.50   $ 1.45   $ 1.43  

PSRI

    (0.01 )   0.01     (0.08 )
               

Earnings per share — continuing operations

    1.49     1.46     1.35  

Discontinued operations

    (0.01 )        
               

Total GAAP earnings per share — diluted

  $ 1.48   $ 1.46   $ 1.35  
               

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.

The following table summarizes the earnings contributions of Xcel Energy's business segments on the basis of GAAP. See Note 4 to the consolidated financial statements for a further discussion of discontinued operations.

 
  Contributions to Earnings  
 
  2009   2008   2007  
 
  (Millions of Dollars)
 

GAAP income (loss) by segment

                   

Regulated electric income — continuing operations

  $ 611.9   $ 552.3   $ 554.7  

Regulated natural gas income — continuing operations

    108.9     129.3     108.0  

Other regulated income(a)

    27.2     27.0     (26.7 )
               
 

Segment income — continuing operations

    748.0     708.6     636.0  

Holding company and other costs(a)

    (62.5 )   (62.9 )   (60.1 )
               
 

Total income — continuing operations

    685.5     645.7     575.9  

Discontinued operations

    (4.6 )   (0.1 )   1.4  
               
 

Total GAAP net income

  $ 680.9   $ 645.6   $ 577.3  
               

 

 
  Contributions to Earnings Per Share  
 
  2009   2008   2007  
 
  (Dollars per Share)
 

GAAP earnings (loss) by segment

                   

Regulated electric — continuing operations

  $ 1.33   $ 1.25   $ 1.28  

Regulated natural gas — continuing operations

    0.24     0.29     0.25  

Other regulated income(a)

    0.06     0.06     (0.06 )
               
 

Segment earnings per share — continuing operations

    1.63     1.60     1.47  

Holding company and other costs(a)

    (0.14 )   (0.14 )   (0.12 )
               
 

Total earnings per share — continuing operations

    1.49     1.46     1.35  

Discontinued operations

    (0.01 )        
               

Total GAAP earnings per share — diluted

  $ 1.48   $ 1.46   $ 1.35  
               

(a)
Not a reportable segment. Included in all other segment results in Note 20 to the consolidated financial statements.

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Higher 2009 ongoing earnings were primarily due to improved electric margins as a result of constructive rate case outcomes in Minnesota, Colorado, Texas, New Mexico and Wisconsin, which were partially mitigated by the negative impact of weather, lower sales and higher purchase capacity power costs. Offsetting stronger electric margins were higher operating and maintenance expenses, resulting from increased employee benefit costs as well as higher nuclear expenses, and dilution from the issuance of equity to fund the capital investment program.

Earnings from continuing operations for 2008 were higher than in 2007 primarily attributed to lower O&M expense, higher electric and gas margins, and higher AFUDC — equity. Partially offsetting these positive factors were higher depreciation and amortization, higher conservation and DSM program expenses, increased interest expense and a higher ETR.


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.

WeatherXcel 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 O&M expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce O&M 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.

Estimated Impact of Temperature Changes on Regulated EarningsThe following table summarizes the estimated impact on earnings per share of temperature variations compared with sales under normal weather conditions.

 
  2009 vs. Normal   2008 vs. Normal   2009 vs. 2008   2007 vs. Normal   2008 vs. 2007  

Retail electric

  $ (0.05 ) $ (0.01 ) $ (0.04 ) $ 0.06   $ (0.07 )

Firm natural gas

        0.01     (0.01 )       0.01  
                       

Total

  $ (0.05 ) $   $ (0.05 ) $ 0.06   $ (0.06 )
                       

Sales Growth (Decline)The following table summarizes Xcel Energy's regulated sales growth (decline) for actual and weather-normalized energy sales for the years ended Dec. 31, compared with the previous year. The year-end sales growth amounts for 2008 have been adjusted for leap year.

 
  2009   2008  
 
  Actual   Normalized   Actual   Normalized  

Electric residential

    (1.4 )%   0.7 %   (2.0 )%    — %

Electric commercial and industrial

    (3.3 )   (2.7 )   1.5     2.4  
 

Total retail electric sales

    (2.7 )   (1.8 )   0.5     1.7  

Firm natural gas sales

    (2.6 )   0.1     4.9     1.9  

During 2009, we experienced lower than anticipated actual electric residential sales, and a decline in electric commercial and industrial sales on a weather-adjusted basis, which we believe was driven by overall economic conditions and to a lesser degree, increased conservation efforts. The declines in MwH sales to the commercial and industrial customer class, which are directly related to the economic downturn, are partially offset by demand charges, which mitigate, to a certain degree, the impact of the lower MwH sales. We anticipate that sales will grow in the future at a slower rate than historical levels in part due to increased conservation activities. Weather-normalized sales for 2010 are projected to grow approximately 1 percent for retail electric customers and to decline approximately 1 percent to 2 percent for retail firm natural gas customers.

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Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers in most states, the fluctuations in these costs do not materially affect electric margin. The following tables detail the change in electric revenues and margin:

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Electric revenues

  $ 7,705   $ 8,683   $ 7,848  

Electric fuel and purchased power

    (3,672 )   (4,948 )   (4,137 )
               
 

Electric margin

  $ 4,033   $ 3,735   $ 3,711  
               

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

Electric Revenues

 
  2009 vs. 2008  
 
  (Millions of Dollars)
 

Fuel and purchased power cost recovery

  $ (1,237 )

Trading

    (73 )

Estimated impact of weather

    (26 )

Retail sales decline (excluding weather impact)

    (22 )

Retail rate increases (Colorado, Minnesota, Texas, New Mexico and Wisconsin)

    218  

Conservation and DSM revenue and incentive (generally offset by expenses)

    74  

Non-fuel riders

    22  

MERP rider

    17  

2008 refund of nuclear refueling outage revenues due to change in recovery method

    16  

Transmission revenue

    14  

SPS 2008 fuel cost allocation regulatory accruals

    12  

Sales mix and demand revenues

    4  

Other, net

    3  
       
 

Total decrease in electric revenue

  $ (978 )
       

2009 Comparison with 2008Electric revenues decreased due to lower fuel and purchased power costs, largely due to lower customer usage and lower commodity prices, lower trading and weather. This was partially offset by retail rate increases in Colorado, Minnesota, Texas, New Mexico and Wisconsin, higher conservation and non-fuel rider recovery, mostly from the RESA rider at PSCO and the RCRF rider at SPS.

 
  2008 vs. 2007  
 
  (Millions of Dollars)
 

Fuel and purchased power cost recovery

  $ 722  

Conservation and non-fuel riders (partially offset in depreciation and amortization expense)

    48  

Retail rate increases (Wisconsin, North Dakota, Texas interim and New Mexico)

    48  

Retail sales growth (excluding weather impact)

    30  

MERP rider

    23  

Transmission revenue

    9  

Increased revenue due to leap year (weather normalized impact)

    9  

Estimated impact of weather

    (49 )

Revenue subject to refund due to change in nuclear refueling outage recovery method

    (18 )

Firm wholesale

    (10 )

Retail customer sales mix

    (8 )

Other (including fuel recovery), net

    31  
       
 

Total increase in electric revenue

  $ 835  
       

2008 Comparison with 2007Electric revenues increased due to higher fuel and purchased power costs, largely recovered from customers, higher conservation and non-fuel rider recovery, mostly from the RESA rider at PSCO and the RES rider at NSP-Minnesota, electric retail rate increases in Wisconsin, North Dakota, Texas and New Mexico and weather-normalized retail sales growth. Unfavorable weather partially offset the positive variances.

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Electric Margin

 
  2009 vs. 2008  
 
  (Millions of Dollars)
 

Retail rate increases (Colorado, Minnesota, Texas, New Mexico and Wisconsin)

  $ 218  

Conservation and DSM revenue and incentive (partially offset by expenses)

    74  

Non-fuel riders

    22  

MERP rider

    17  

2008 refund of nuclear refueling outage revenues due to change in recovery method

    16  

NSP-Wisconsin fuel recovery

    14  

SPS 2008 fuel cost allocation regulatory accruals

    12  

Firm wholesale

    11  

Sales mix and demand revenues

    4  

Purchased capacity costs

    (44 )

Estimated impact of weather

    (26 )

Retail sales decline (excluding weather impact)

    (22 )

Other, net

    2  
       
 

Total increase in electric margin

  $ 298  
       

2009 Comparison to 2008The increase in electric margin was due to electric rate increases in Colorado, Minnesota, Texas, New Mexico and Wisconsin, higher conservation and DSM revenue and non-fuel riders. This was partially offset by higher purchase capacity costs and a negative impact of weather.

 
  2008 vs. 2007  
 
  (Millions of Dollars)
 

Retail rate increases (Wisconsin, North Dakota, Texas interim and New Mexico)

  $ 48  

Retail sales growth (excluding weather impact)

    30  

Conservation and non-fuel riders

    28  

MERP rider

    23  

Increased revenue due to leap year (weather normalized impact)

    9  

Estimated impact of weather

    (49 )

Purchased capacity costs

    (30 )

Revenue subject to refund due to change in nuclear refueling outage recovery method

    (18 )

Trading margin

    (10 )

Retail customer sales mix

    (8 )

Other (including fuel recovery), net

    1  
       
 

Total increase in electric margin

  $ 24  
       

2008 Comparison to 2007The increase in electric margin for the year was due to electric rate increases at Wisconsin, North Dakota, Texas and New Mexico, higher conservation and non-fuel rider revenues and weather-normalized retail sales growth. These items were partially offset by unfavorable weather and higher purchased power costs.


Natural Gas 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. The following table details the changes in natural gas revenues and margin.

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Natural gas revenues

  $ 1,866   $ 2,443   $ 2,112  

Cost of natural gas sold and transported

    (1,266 )   (1,833 )   (1,548 )
               
 

Natural gas margin

  $ 600   $ 610   $ 564  
               

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Natural Gas Revenues

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

 
  2009 vs. 2008  
 
  (Millions of Dollars)
 

Purchased natural gas adjustment clause recovery

  $ (568 )

Estimated impact of weather

    (10 )

Conservation and DSM revenue and incentive

    6  

Other (including sales mix), net

    (5 )
       
 

Total decrease in natural gas revenues

  $ (577 )
       

2009 Comparison to 2008Natural gas revenues decreased primarily due to lower natural gas costs in 2009, and the estimated impact of weather.

 
  2008 vs. 2007  
 
  (Millions of Dollars)
 

Purchased natural gas adjustment clause recovery

  $ 282  

Base rate changes

    24  

Estimated impact of weather

    10  

Sales growth (excluding impact of weather)

    5  

Conservation revenues

    3  

Revenue due to leap year (weather normalized impact)

    1  

Transportation

    1  

Other (including late payment fees), net

    5  
       
 

Total increase in natural gas revenues

  $ 331  
       

2008 Comparison to 2007Natural gas revenues increased primarily due to higher natural gas costs in 2008 which are recovered from customers. Final gas rates were effective for Wisconsin in January 2008 and Minnesota in February 2008. Phase I rates were effective in Colorado since July 2007.

Natural Gas Margin

 
  2009 vs. 2008  
 
  (Millions of Dollars)
 

Estimated impact of weather

    (10 )

Conservation and DSM revenue and incentive (partially offset by expenses)

    6  

Other (including sales mix), net

    (6 )
       
 

Total decrease in natural gas margin

  $ (10 )
       

2009 Comparison to 2008Natural gas margins decreased mainly due to milder than normal temperatures.

 
  2008 vs. 2007  
 
  (Millions of Dollars)
 

Base rate changes (Colorado and Wisconsin)

  $ 24  

Estimated impact of weather

    10  

Sales growth (excluding impact of weather)

    5  

Conservation revenues

    3  

Increased margin due to leap year (weather normalized impact)

    1  

Transportation

    (1 )

Other, net

    4  
       
 

Total increase in natural gas margin

  $ 46  
       

2008 Comparison to 2007Natural gas margins increased due to base rate increases for Wisconsin in January 2008 and Colorado since July 2007.

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Non-Fuel Operating Expenses and Other Items

Other O&M ExpensesO&M Expenses increased by approximately $130.2 million, or 7.3 percent, in 2009, compared with 2008, and decreased by 11.0 million or 0.6 percent, compared with 2007.

 
  2009 vs. 2008  
 
  (Millions of Dollars)
 

Higher employee benefit costs

  $ 90  

Nuclear outage costs, net of deferral

    30  

Higher nuclear plant operation costs

    21  

Higher plant generation costs

    9  

Higher insurance costs

    7  

Higher information technology costs

    6  

Higher labor costs

    6  

Lower consulting costs

    (18 )

Lower uncollectible receivable costs

    (14 )

Lower material costs

    (4 )

Other, net

    (3 )
       
 

Total increase in other operating and maintenance expenses

  $ 130  
       

2009 Comparison to 2008The decrease in O&M expenses for 2009 was largely driven by the following:

Higher employee benefits costs are primarily attributable to 2009 employee performance based incentive compensation expenses, higher pension expenses and increased medical expenses. In 2008, no employee performance based incentive benefits were earned.

The increase in nuclear outage costs is due to the commissions' approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in 2008.

The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new NRC requirements.

Lower consulting costs are primarily the result of cost management initiatives achieved throughout 2009.

Lower uncollectible receivable costs are mainly due to improved collections and a decrease in natural gas prices.

 
  2008 vs. 2007  
 
  (Millions of Dollars)
 

Lower employee benefit costs

  $ (39 )

Nuclear outage costs, net of deferral

    (13 )

Higher labor costs

    22  

Higher plant generation costs

    9  

Higher consulting operation costs

    7  

Higher allowance for bad debts

    7  

Higher contract labor costs

    4  

Higher material costs

    2  

Other (including nuclear plant operation costs), net

    (10 )
       
 

Total decrease in other operating and maintenance expenses

  $ (11 )
       

2008 Comparison to 2007The decrease in O&M expenses for 2008 was largely driven by the following:

The decline in nuclear outage expense is due to the MPUC, NDPSC, and SDPUC approving the change in recovery methods for costs associated with refueling outages at Xcel Energy's nuclear plants from the direct expense method to the deferral and amortization method, effective Jan. 1, 2008. An accrual was also recorded to lower revenue, reflecting a liability for a customer refund relating to this decision.

Lower employee benefit costs are due to eliminating our annual performance based incentive plan payout for 2008.

The higher plant generation costs were primarily attributable to scheduled and unplanned maintenance.

The increase in labor costs was attributable to annual wage increases, the insourcing of certain functions and additional employees to support system growth.

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Conservation and DSM ExpensesConservation and DSM program expenses increased by approximately $64.4 million for 2009, compared with 2008, and by approximately $15.9 million for 2008, compared with 2007. The higher expense for 2009 and 2008 was attributable to the expansion of programs and regulatory commitments. Conservation and DSM program expenses and financial incentives are recovered through riders or base rates.

Depreciation and AmortizationDepreciation and amortization expenses decreased by approximately $10.3 million, or 1.2 percent, for 2009, compared with 2008. In 2009, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, as a result of the MPUC decision in the Minnesota electric rate case. In addition, in 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decisions reduced depreciation and decommissioning expense in 2009. These decreases were partially offset by normal system expansion.

Depreciation and amortization expenses increased by $22.6 million, or 2.8 percent for 2008 when compared with 2007. The increase was primarily due to planned system expansion partially offset by a decrease in depreciation due to the MPUC approval of two NSP-Minnesota depreciation filings in September 2008 and a NDPSC settlement agreement in December 2008.

Taxes (Other Than Income Taxes)Taxes (other than income taxes) increased by approximately $19.9 million, or 6.9 percent, for 2009, compared with 2008, and by approximately $8.9 million, or 3.2 percent, for 2008 compared with 2007. The increase was primarily due to increased property taxes across our jurisdictions.

Other Income, NetOther income, net, decreased by $30.6 million for 2009 compared with 2008. The net decline was mainly due to changes in our non-qualified benefit plan liabilities related to market activity, lower interest on under recovered deferred fuel balances and a decrease in interest received from WYCO for construction deposits.

Other income, net, increased by $33.0 million, for 2008 when compared with 2007. The increase was primarily the result of PSRI's termination of the COLI program in 2007, which eliminated certain expenses.

Equity Earnings of Unconsolidated SubsidiariesEquity earnings of unconsolidated subsidiaries increased by approximately $21.1 million for 2009, compared with 2008, and by approximately 1.7 million for 2008, compared with 2007. The increase was primarily due to higher earnings from the equity investment in WYCO as a result of the High Plains natural gas pipeline, located in Colorado, which commenced operations in late 2008 as well as a gas storage facility that began operations in July 2009.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC)AFUDC increased by approximately $12.9 million, or 12.6 percent for 2009, compared with 2008, and by $30.8 million, or 42.8 percent, for 2008 when compared with 2007. The increase was due primarily to the construction of Comanche Unit 3, a power facility located in Colorado, as well as other construction projects.

Interest ChargesInterest charges increased by approximately $8.7 million, or 1.6 percent, for 2009, compared with 2008. The increase was primarily the result of increased debt levels to fund new capital investments, partially offset by lower interest rates on short-term debt.

Interest charges increased by $33 million, or 6.3 percent, for 2008 when compared with 2007. The increase was primarily the result of increased debt levels to fund Xcel Energy's rate base growth strategy.

Income TaxesIncome tax expense for continuing operations increased by $32.6 million for 2009, compared with 2008. The increase in income tax expense was primarily due to an increase in pretax income. The ETR for continuing operations was 35.1 percent for 2009, compared with 34.4 percent for 2008. The higher ETR for 2009 was primarily due to the establishment of a valuation allowance against certain state tax credit carryovers that are now expected to expire prior to full utilization. Excluding this item, the ETR for 2009 would have been 34.6 percent.

Income taxes for continuing operations increased by $44.2 million for 2008, compared with 2007. The increase in income tax expense was primarily due to an increase in pretax income in 2008. The ETR for continuing operations was 34.4 percent for 2008, compared with 33.8 percent for 2007.

The ETRs for 2009 and 2008 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant related regulatory differences. The ETR for 2007 differs from its statutory federal income tax rate, primarily due to state income tax expense partially offset by tax credits recognized and tax benefits from life insurance policies and plant related regulatory differences. See Note 8 to the consolidated financial statements.

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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  
 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Financing costs and preferred dividends — Holding Company

  $ (65.6 ) $ (69.7 ) $ (71.9 )

Eloigne

    (4.7 )   1.5     2.6  

Holding Company, taxes and other results

    7.8     5.3     9.2  
               
 

Total Holding Company and other loss — continuing operations

  $ (62.5 ) $ (62.9 ) $ (60.1 )
               

 

 
  Contribution to Xcel Energy's Earnings Per Share  
 
  2009   2008   2007  
 
  (Dollars per Share)
 

Financing costs and preferred dividends — Holding Company

  $ (0.14 ) $ (0.15 ) $ (0.15 )

Eloigne

    (0.01 )        

Holding Company, taxes and other results

    0.01     0.01     0.03  
               
 

Total Holding Company and other loss per share — continuing operations

  $ (0.14 ) $ (0.14 ) $ (0.12 )
               

Financing Costs and Preferred DividendsHolding 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.

EloigneEloigne contributed a loss of approximately $4.7 million which was primarily attributed to the sale of property in 2009.


Factors Affecting Results of Continuing Operations

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

General Economic Conditions

Economic conditions may have a material impact on Xcel Energy's operating results. Management cannot predict the impact of a prolonged economic recession, 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 sustained general slowdown in future economic growth or a significant increase in interest rates.

Fuel Supply and Costs

Xcel Energy's operating utilities have varying dependence on coal, natural gas and uranium. Changes in commodity prices are generally recovered through fuel recovery mechanisms and have very little impact on earnings. However, availability of supply, the potential implementation of a carbon tax and unanticipated changes in regulatory recovery mechanisms could impact our operations. See additional discussion of fuel supply and costs under Item 1 — Electric Utility Operations.

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 include changes in interest rates and market returns. Changes in the related net pension and postretirement benefits costs and funding requirements 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.

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Regulation

Customer Rate RegulationThe 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, which is affected by overall economic conditions, conservation and DSM efforts and the cost of capital. In addition, the ROE authorized is set by regulatory commissions in rate proceedings.

Wholesale Energy Market RegulationWholesale energy markets are operated by MISO to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. MISO centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin. In January 2009, MISO implemented modifications to the original market to establish a regional ASM. The ASM provides 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 original energy market. NSP-Minnesota and NSP-Wisconsin expect to recover MISO charges through either base rates or various recovery mechanisms. See Note 16 to the consolidated financial statements for further discussion.

Capital Expenditure RegulationXcel 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, MPUC, SDPUC and PUCT approved proposals to recover, through a rate rider, costs to upgrade generation plants and lower emissions, and/or increase transmission investment cost. 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.

Proposed Legislation

Minnesota Legislation Relating to Utility Interim Rates and Expense DisclosureIn January 2010, the Minnesota attorney general held a press conference announcing two proposed bills for the 2010 legislative session. One bill would eliminate interim rates in utility general rates cases, in most instances. The second bill would require disclosure of expense, meal and travel compensation for the top 10 officers and corporate aviation expenses of public utilities. While it is uncertain if these bills will become law, the elimination of interim rate recovery could have an adverse impact on NSP-Minnesota's ability to earn its authorized return and continue to make significant capital investment in Minnesota.

Other

Minnesota Office of Pipeline Safety (MnOPS)-Notice of Probable Violation (NPV)On Feb. 1, 2010, a plumber working to clear a sewer line at a residence in St. Paul, Minn. struck a gas line, which ignited a fire that destroyed the house. The plumber received minor burns, was treated and released that night, and no other injuries resulted. An investigation revealed that the gas line to the house had penetrated and intersected the sewer line to the home. On Feb. 5, 2010, MnOPS delivered an NPV to NSP-Minnesota. The NPV states that NSP-Minnesota failed to take appropriate measures to prevent this accident from occurring in violation of state and federal regulations. The NPV also sets forth a four-part proposed compliance plan and a $1 million fine. The compliance order requires, among other things, that NSP-Minnesota submit an inspection and remediation plan. NSP-Minnesota subsequently investigated the sewer lines in the vicinity of the accident and determined that no additional conflicts exist. NSP-Minnesota intends to respond to the NPV on March 8, 2010.

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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:

$225 million in 2009;

$213 million in 2008; and

$173 million in 2007.

Xcel Energy expects to expense an average of approximately $256 million per year from 2010 through 2014 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:

$89 million in 2009;

$230 million in 2008; and

$439 million in 2007.

Xcel Energy expects to incur approximately $79 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2010, and approximately $530 million of related expenditures from 2011 through 2014. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado.

See Note 17 to the consolidated financial statements for further discussion of Xcel Energy's environmental contingencies.

Generating facilities throughout the Xcel Energy territory currently are subject to mercury reduction requirements only at the state level. In Minnesota mercury emissions from A. S. King and Sherco generating facilities are regulated by the Minnesota Mercury Legislation, and in Colorado, eight units are subject to a mercury emissions rule passed by the Colorado Air Quality Control Commission (AQCC).

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010. In November 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

In December 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the MPCA. Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

The EPA has required states to develop implementation plans to comply with BART, which included identification of facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. The Colorado AQCC promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. PSCo estimates that implementation of BART alternatives will cost approximately $254 million in capital costs, which includes approximately $113 million in environmental upgrades for the existing Comanche Station Units 1 and 2 project, which are included in the capital budget. PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2014. Colorado's state implementation plan has been submitted to EPA for approval. In January 2009, the CAPCD initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado's Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.

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Inflation

Inflation at its current level is not expected to materially affect Xcel Energy's prices or returns to shareholders. However, potential future inflation resulting from the economic and monetary stimulus policies of the U. S. Government and the Federal Reserve could lead to future price increases for materials and services required to deliver electric and natural gas services to customers. These potential cost increases could in turn lead to increased prices to customers.


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 ASC 980 Regulated Operations, which 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, 2009 and 2008, Xcel Energy has recorded regulatory assets of approximately $2.3 billion and $2.4 billion and regulatory liabilities of approximately $1.2 billion and $1.2 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 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 19 for additional details on regulatory assets and liabilities.


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 the ETR.

ETRs 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 ASC 740 Income Taxes, 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.

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ASC 740 Income Taxes also 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 needs to be reasonably estimated based on evaluation of the nature of uncertainty, the nature of event that could cause the change and an estimated 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 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 8 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 11 to the consolidated financial statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs and funding requirements are expected to increase in the next few years as a result of significantly lower-than-expected investment returns in 2008. While investment returns exceeded the assumed levels from 2004-2006, and during 2009, investment returns in 2007 and 2008 were below the assumed levels. The investment gains or losses resulting from the difference between the expected pension returns and actual returns earned are deferred in the year the difference arises and are recognized over the expected average remaining years of service for active employees. Based on current assumptions and the recognition of past investment gains and losses, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes will increase from income of $3.0 million in 2008 and an expense of $12.9 million in 2009 to expense of $36 million in 2010 and expense of $110 million in 2011. The potential increase in the 2011 expense is due to expense recognition based on cash funding and expected cash contributions of $55 million in 2011 at NSP-Minnesota compared to no contributions made during 2008 through 2010.

Xcel Energy set the discount rate used to value the Dec. 31, 2009 pension and postretirement health care obligations at 6 percent, which is a 75 basis point decrease from Dec. 31, 2008. Xcel Energy uses multiple reference points in determining the discount rate, including Citigroup Pension Liability Discount Curve, the Citigroup Above Median Curve and bond matching studies. At Dec. 31, 2009, the above reference points supported the selected rate. In addition to the reference points utilized above, Xcel Energy also reviews general survey data provided by our actuaries to assess the reasonableness of the discount rate selected.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009. Xcel Energy currently projects no additional funding for 2010 and cash funding of $100 million to $150 million in 2011. For future years, we anticipate contributions will be made to avoid benefit restrictions and at-risk status.

These expected contributions are summarized in Note 11 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 Dec. 31, 2009, pension expense determinations, a one-percent change would result in the following impact on the estimates recognized:

 
  Pension Costs  
 
  +1%   -1%  
 
  (Millions of Dollars)
 

Rate of return

  $ (20.0 ) $ 20.0  

Discount rate

    (6.0 )   8.5  

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Effective Dec. 31, 2009, Xcel Energy reduced its initial medical trend assumption from 7.4 percent to 6.8 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is three 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.

Xcel Energy contributed $62.2 million during 2009 and $55.6 million during 2008 to the postretirement health care plans. Xcel Energy expects to contribute approximately $45.4 million during 2010.

See Note 11 to the consolidated financial statements for additional discussion of Xcel Energy's benefit plans.


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 ASC 980 Regulated Operations.

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 2067 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 set the escalation rate at 2.89 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 2030 for Monticello and in 2023 and 2024 for Prairie Island's two facilities. Changes made to decommissioning cost estimates, the escalation rate and the earnings rate can be affected by changes to these life periods. With the recent re-licensing of Monticello and the application for the re-licensing of Prairie Island, any change in license life could have a material effect on the accrual. Current decommissioning cost calculations for Monticello have assumed full life extension, which brings the regulatory recovery period up to 2030. An application to extend the operating licenses for both reactors at Prairie Island by 20 years was submitted to the NRC in 2008. The NRC is expected to decide on the application in late 2010 or early in 2011. In the interim, the MPUC has extended the recovery period for Prairie Island Unit 1 to 2023 and Unit 2 to 2024. These changes were effective Jan. 1, 2009.

As a result of the studies for Monticello and Prairie Island nuclear plants, the nuclear production decommissioning ARO and related regulatory asset decreased by $128.5 million and $139.3 million, respectively, in the fourth quarter of 2008. It was further reduced by $315.9 million in the fourth quarter of 2009 for the Prairie Island nuclear plant relating to the approved change in recovery period.

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Revisions were made for asbestos, ash-containment facilities, nuclear plants, wind turbines, radiation sources and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

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 and other commissions. 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. 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 6.3 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 $881.5 million and $207.3 million, respectively, as of Dec. 31, 2009, and $1.1 billion and $299.3 million, respectively, as of Dec. 31, 2008. 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 ASC 410 Asset Retirement and Environmental Obligations are deferred as a regulatory asset.

See Note 18 for further discussion regarding nuclear decommissioning.

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, 2009.

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


Recent and Pending Accounting Changes

Recently Adopted

Business Combinations — In December 2007, the FASB issued new guidance on business combinations 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. This new guidance 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 implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

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Noncontrolling Interests — Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent's equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent's ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Derivatives and Hedging Disclosures — In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity's financial position, financial performance and cash flows. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 13 to the consolidated financial statements.

Interim Fair Value Disclosures — In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Fair Value in Inactive Markets — Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly. The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Other-Than-Temporary Impairments — Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance was effective for interim and annual periods ending after June 15, 2009. Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Accounting Standards Codification — In June 2009, the FASB issued Topic 105 — Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. Xcel Energy implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on Xcel Energy's consolidated financial statements.

Postretirement Benefit Plans — In December 2008, the FASB issued new guidance on employers' disclosures about postretirement benefit plan assets. The guidance amends and expands previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements. This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009. Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 11 to the consolidated financial statements.

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Fair Value of Liabilities — In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value (ASU No. 2009-05), which updates the Codification with clarifications for measuring the fair value of liabilities. The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model. The updates to the Codification contained in ASU No. 2009-05 were effective for interim and annual periods beginning after its August, 2009 issuance. Xcel Energy implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Recently Issued

Consolidation of Variable Interest EntitiesIn June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity's primary beneficiary. This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009. Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

Fair Value Measurement DisclosuresIn January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. Xcel Energy does not expect the implementation of the guidance to have a material impact 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. Market risks associated with derivatives are discussed in further detail in Note 13 to the consolidated financial statements.

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

Commodity Price RiskXcel 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 RiskXcel Energy's utility subsidiaries conduct various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and 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.

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

 
  2009   2008  
 
  (Thousands of Dollars)
 

Fair value of commodity trading net contract assets outstanding at Jan. 1

  $ 4,169   $ 6,315  

Contracts realized or settled during the period

    (21,740 )   (1,574 )

Commodity trading contract additions and changes during period

    27,199     (572 )
           

Fair value of commodity trading net contract assets outstanding at Dec. 31

  $ 9,628   $ 4,169  
           

At Dec. 31, 2009, the fair values by source for the commodity trading net asset balance 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 Value
 
 
  (Thousands of Dollars)
 

NSP-Minnesota

    1   $ (319 ) $ 2,577   $   $   $ 2,258  

    2     2,338     4,220     160         6,718  

PSCo

    1     (1,055 )   1,158             103  

    2     31     222     296         549  
                             

        $ 995   $ 8,177   $ 456   $   $ 9,628  
                             

1—
Prices actively quoted or based on actively quoted prices.
2—
Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management's estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

Normal purchases and sales transactions, as defined by ASC 815 Derivatives and Hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

At Dec. 31, 2009, 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 $0.9 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.9 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 Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis, were as follows:

 
  Year Ended
Dec. 31
  VaR Limit   Average   High   Low  
 
  (Millions of Dollars)
 

2009

  $ 0.50   $ 5.00   $ 0.44   $ 2.02   $ 0.06  

2008

    0.30     5.00     0.30     1.14     0.01  

Interest Rate RiskXcel 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, 2009, a 100-basis-point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense by approximately $5.4 million annually. See Note 13 to the consolidated financial statements for a discussion of Xcel Energy and its subsidiaries' interest rate derivatives.

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Xcel Energy also maintains 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, 2009, these funds were invested in a diversified portfolio of taxable and municipal fixed income securities and equity 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 RiskXcel Energy and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their 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.

At Dec. 31, 2009, a 10 percent increase in prices would have resulted in an increase in credit exposure of $26.5 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $4.9 million.

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


Fair Value Measurements

Xcel Energy adopted new accounting and disclosure guidance on fair value measurements on Jan. 1, 2008 which established a hierarchy for inputs used in measuring fair value, and generally requires that the most observable inputs available be used for fair value measurements. Note 15 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity DerivativesXcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty's ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2009. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2009.

Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability. Level 3 commodity derivative assets and liabilities represent approximately 3 percent and 53 percent of total assets and liabilities measured at fair value, respectively, at Dec. 31, 2009.

Determining the fair value of a FTR requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management's forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities include $23.6 million and $3.3 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2009.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. Level 3 commodity derivatives assets and liabilities include $20.3 million and $12.6 million of estimated fair values, respectively, for commodity forwards and options held at Dec. 31, 2009.

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Nuclear Decommissioning FundNuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities. To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities, however, less observable and subjective risk-based adjustments to estimated yield and forecasted prepayments are often significant to these valuations. Therefore, estimated fair values for all asset-backed and mortgage-backed securities totaling $93.1 million in the nuclear decommissioning fund at Dec. 31, 2009 (approximately 7 percent of total assets measured at fair value), are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.


Liquidity and Capital Resources

Cash Flows

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Cash provided by (used in) operating activities

                   

Continuing operations

  $ 1,946   $ 1,683   $ 1,560  

Discontinued operations

    (28 )   (3 )   72  
               
 

Total

  $ 1,918   $ 1,680   $ 1,632  
               

Cash provided by operating activities for continuing operations increased by $263 million for 2009 as compared to 2008. The increase was primarily attributable to higher net income, changes in working capital due to the timing of accounts receivable, accounts payable and inventory as a result of natural gas prices and an increase in plant-related deferred income taxes. The increase was partially offset by increased pension contributions made in 2009 and higher AFUDC due primarily to the construction of Comanche Unit 3, a power facility located in Colorado.

Cash provided by operating activities for continuing operations increased by $123 million for 2008 as compared to 2007. The increase is primarily attributable to higher net income, changes in other current liabilities due to timing for interest payable and accounts payable and an increase in recoverable gas and electric costs. This increase was partially offset by changes in working capital activity due to increased inventory, contributions for pension and non-pension postretirement benefits, and an increase in net regulatory assets and liabilities. The increased inventory reflects the higher cost of natural gas combined with an increase in storage contracts. The increase in net regulatory assets and liabilities reflects the increase in pension funding obligation, and the decrease in fair value of the investments in the decommissioning fund, partially offset by the decrease in the asset retirement obligation for the extended life of the nuclear facilities. Cash provided by operating activities for discontinued operations decreased $75 million, primarily due to decreased income taxes received during 2008.

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Cash used in investing activities

  $ (1,735 ) $ (2,156 ) $ (2,082 )

Cash used in investing activities for continuing operations decreased by $421 million during 2009, primarily due to reduced capital expenditures; a withdrawal of funds, to refund customers, from the external decommissioning fund as approved by the MPUC; as well as reduced investment in the WYCO natural gas pipeline and storage project. No cash was provided by investing activities for discontinued operations.

Cash used in investing activities for continuing operations increased by $74 million during 2008, primarily due to increased capital expenditures, and the continued investment in the WYCO natural gas pipeline and storage project.

 
  2009   2008   2007  
 
  (Millions of Dollars)
 

Cash provided by (used in) financing activities

  $ (322 ) $ 671   $ 483  

Cash used in financing activities related to continuing operations increased by $993 million during 2009, primarily due to lower proceeds from the issuances of long-term debt and common stock and an increase in dividends, partially offset by lower repayments of short-term borrowings.

Cash provided by financing activities related to continuing operations increased by $188 million during 2008 due to the issuance of long-term debt and approximately 17.3 million shares of common stock in 2008. This was partially offset by repayments of short-term borrowings.

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

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Capital Requirements

Utility Capital ExpendituresThe estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2010 through 2013 are shown in the tables below.

 
  2010   2011   2012   2013  
 
  (Millions of Dollars)
 

By Subsidiary
                         

NSP-Minnesota

  $ 1,220   $ 1,240   $ 1,000   $ 1,440  

NSP-Wisconsin

    135     155     160     160  

PSCo

    610     600     710     815  

SPS

    270     295     255     260  
                   
 

Total capital expenditures

  $ 2,235   $ 2,290   $ 2,125   $ 2,675  
                   

 

By Function
  2010   2011   2012   2013  

Electric generation

  $ 345   $ 425   $ 405   $ 570  

Electric transmission

    465     480     725     915  

Electric distribution

    405     405     440     475  

Wind

    460     390          

Gas

    170     190     180     205  

Nuclear fuel

    95     105     140     100  

Nuclear uprate and life extension

    130     145     75     240  

Common and other

    165     150     160     170  
                   
 

Total capital expenditures

  $ 2,235   $ 2,290   $ 2,125   $ 2,675  
                   

 

By Project
  2010   2011   2012   2013  

Base and other capital expenditures

  $ 1,530   $ 1,415   $ 1,450   $ 1,600  

NSP-Minnesota wind generation

    460     390          

Nuclear capacity increases and life extension

    130     145     75     240  

NSP-Minnesota wind transmission and CapX 2020

    65     160     385     545  

Jones repowering

    20     75     35      

Transmission projects

    15     85     160     115  

Sherco capacity increases

    15     15         15  

High Plains Express

        5     10     50  

Black Dog repowering

            10     110  
                   
 

Total capital expenditures

  $ 2,235   $ 2,290   $ 2,125   $ 2,675  
                   

Many of the states in which Xcel Energy operates have enacted RESs, which may require significant increases in investment in renewable generation and transmission. Xcel Energy is 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 potential increased investments for renewable generation and transmission assets.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions and approvals, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy's long-term energy needs. In addition, Xcel Energy's ongoing evaluation of restructuring requirements, compliance with future environmental requirements and RPSs to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. See additional discussion in Item 1 — Electric Utility Operations.

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Contractual Obligations and Other CommitmentsXcel 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, 2009. See additional discussion in the consolidated statements of capitalization and Notes 5, 6, and 17 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

  $ 16,835,823   $ 1,043,029   $ 2,026,815   $ 1,277,458   $ 12,488,521  

Capital lease obligations

    434,313     17,147     36,100     34,759     346,307  

Operating leases(a)(b)

    3,322,120     175,773     358,531     398,669     2,389,147  

Unconditional purchase obligations

    10,579,953     2,329,869     2,867,773     1,555,533     3,826,778  

Other long-term obligations — WYCO investment

    6,973     6,973              

Other long-term obligations(c)

    162,479     31,383     60,405     57,853     12,838  

Payments to vendors in process

    104,025     104,025              

Short-term debt

    459,000     459,000              
                       
 

Total contractual cash obligations(d)(e)(f)(g)

  $ 31,904,686   $ 4,167,199   $ 5,349,624   $ 3,324,272   $ 19,063,591  
                       

(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, 2009, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $110.3 million. In addition, at the end of the equipment lease terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value of equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.
(b)
Included in operating lease payments are $151.7 million, $307.6 million, $354.1 million and $2.3 billion, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to purchase power agreements that were accounted for as operating leases.
(c)
Included in other long-term obligations are tax and interest related to unrecognized tax benefits recorded as required under ASC 740 Income Taxes.
(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 $2.1 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.
(f)
Xcel Energy currently projects no additional pension funding obligations for 2010. At this time, pension funding contributions for 2011, which will be dependent on several factors including realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million.
(g)
Xcel Energy expects to contribute approximately $45.4 million to the postretirement health care plans during 2010.

Common Stock DividendsFuture 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 utility subsidiaries dividends may be limited indirectly or directly by state regulatory commissions, bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios.

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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 (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends.

Regulation of DerivativesOn Dec. 11, 2009, the U. S. House of Representatives passed H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009, and there are several other bills which have been introduced regarding regulation of derivative transactions. One provision within H.R. 4173 and the other bills introduced provide the Commodity Futures Trading Commission and SEC with expanded regulatory authority of energy derivative and swap transactions. As passed by the House, H.R. 4173 could preclude or impede some types of over-the-counter energy commodity transactions and/or require clearing through regulated central counterparties, which could result in extensive margin and fee requirements. Xcel Energy will further analyze the provisions of this complex legislation to understand potential financial impacts and risk to Xcel Energy, but based on our preliminary analysis the margin requirements could be significant. The legislation passed by the U. S. House of Representatives appears to contain less onerous language on hedges used by commercial participants, however, Xcel Energy is reviewing the proposal. Additionally, the U. S. Senate is scheduled to begin debate on derivatives legislation in early 2010, but the direction of the U. S. Senate is unknown at present.

Pension FundXcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short — term to long-duration fixed income securities, and alternative investments, including, private equity, real estate and commodity index investments. In December 2009, Xcel Energy accelerated its planned 2010 contribution of $100 million, based on available liquidity, bringing its total 2009 pension contributions to $200 million. Xcel Energy currently projects no additional funding obligations for 2010. At this time, pension funding contributions for 2011, which will be dependent on several factors including realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million. The funded status and pension assumptions are summarized in the following tables:

 
  Dec. 31, 2009   Dec. 31, 2008  
 
  (Millions of Dollars)
 

Fair value of pension assets

  $ 2,449   $ 2,185  

Projected pension obligation(a)

    2,830     2,598  
           
 

Funded status

  $ (381 ) $ (413 )
           

(a)
Excludes non-qualified plan of $46 million at Dec. 31, 2009 and 2008, respectively.

Pension Assumptions
  2010   2009  

Discount rate

    6.00 %   6.75 %

Expected long-term rate of return

    7.79     8.50  


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 SourcesXcel Energy uses 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.

Short-Term InvestmentsXcel Energy, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating accounts with Wells Fargo Bank. At Dec. 31, 2009, approximately $35.5 million of cash was held in these liquid operating accounts.

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Commercial PaperXcel Energy, NSP-Minnesota, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:

$800 million for Xcel Energy;

$500 million for NSP-Minnesota;

$700 million for PSCo; and

$250 million for SPS.

Credit FacilitiesAs of Feb. 12, 2010 Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

 
  Facility   Drawn(a)   Available   Cash   Liquidity   Facility
 
  (Millions of Dollars)

NSP-Minnesota

  $ 482.22   $ 30.80   $ 451.42   $ 36.16   $ 487.58   December 2011

PSCo

    675.11     74.65     600.46     2.76     603.22   December 2011

SPS

    247.86     10.00     237.86     44.53     282.39   December 2011

Xcel Energy — Holding Company

    771.56     369.60     401.96     0.42     402.38   December 2011

NSP-Wisconsin(b)

                  0.24     0.24    
                         
 

Total

  $ 2,176.75   $ 485.05   $ 1,691.70   $ 84.11   $ 1,775.81    
                         

(a)
Includes direct borrowings, outstanding commercial paper and letters of credit.
(b)
NSP-Wisconsin does not have a specific credit facility; however, it has a borrowing agreement with NSP-Minnesota.

Listed below is a summary of the banks that make up the credit facilities of Xcel Energy and its subsidiaries as of Feb. 12, 2010.

 
  Xcel Energy
Holding Co.
  PSCo   SPS   NSP-Minnesota   Total  
 
  (Millions of Dollars)
 

Bank of America

  $ 71.11   $ 62.22   $ 22.23   $ 44.44   $ 200.00  

Barclays

    54.22     47.45     16.94     33.89     152.50  

JP Morgan

    54.22     47.45     16.94     33.89     152.50  

Wells Fargo

    62.67     37.33     13.33     26.67     140.00  

Bank of New York-Mellon

    42.67     37.33     13.33     26.67     120.00  

Bank of Tokyo/Mitsubishi

    42.67     37.33     13.33     26.67     120.00  

BMO Capital Markets

    42.67     37.33     13.33     26.67     120.00  

BNP Paribas

    42.67     37.33     13.33     26.67     120.00  

KeyBank National Association

    42.67     37.33     13.33     26.67     120.00  

Morgan Stanley Bank

    42.67     37.33     13.33     26.67     120.00  

Royal Bank of Scotland

    42.67     37.33     13.33     26.67     120.00  

Bank of Nova Scotia

    42.67     37.33     13.33     26.67     120.00  

UBS

    42.67     37.33     13.33     26.67     120.00  

Citibank

    22.67     37.33     13.33     26.67     100.00  

Credit Suisse

    28.44     24.89     8.90     17.77     80.00  

Goldman Sachs

    28.44     24.89     8.90     17.77     80.00  

Mizuho Corporate Bank

    28.44     24.89     8.90     17.77     80.00  

US Bank

    28.44     24.89     8.90     17.77     80.00  

Amarillo National Bank

    8.88     7.80     2.77     5.55     25.00  

Sumitomo

            6.75         6.75  
                       
 

Total

  $ 771.56   $ 675.11   $ 247.86   $ 482.22   $ 2,176.75  
                       

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, credit ratings and access to reasonably priced capital markets. For additional information on Xcel Energy's short-term borrowing arrangements, see Note 5 to the consolidated financial statements.

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Credit RatingsAccess to reasonably priced capital markets is dependent in part on credit 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. 12, 2010, 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   A1   A   A+

NSP-Minnesota

  Commercial Paper   P-2   A-2   F1

NSP-Wisconsin

  Senior Unsecured Debt   A3   A-   A

NSP-Wisconsin

  Senior Secured Debt   A1   A   A+

PSCo

  Senior Unsecured Debt   Baa1   BBB+   A-

PSCo

  Senior Secured Debt   A2   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

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. A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

In August 2009, Moody's upgraded the majority of the senior secured debt ratings of investment-grade regulated utilities by one notch. The senior secured ratings for NSP-Minnesota and NSP-Wisconsin were raised to A1 from A2, and the senior secured rating for PSCo was raised to A2 from A3. In June 2009, S&P revised the outlook on Xcel Energy Inc. and its regulated subsidiaries to Positive from Stable.

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 14 to the consolidated financial statements. Xcel Energy has no explicit credit rating requirements or hard triggers in its debt agreements.

Money PoolXcel 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 investments in and borrowings from the utility subsidiaries and investments from the Holding Company to the utility subsidiaries at market-based interest rates. The money pool balances are eliminated during consolidation.

The utility money pool arrangement does not allow borrowings to the Holding Company. NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.

The borrowings or investments outstanding at Dec. 31, 2009, and the approved short-term borrowing limits from the money pool are as follows:

 
  Borrowings (Investments)   Total Borrowing Limits  
 
  (Millions of Dollars)
 

NSP-Minnesota

  $ (7 ) $ 250  

PSCo

    84     250  

SPS

    (77 )   100  

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Registration StatementsXcel Energy's articles of incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2009 and 2008, Xcel Energy had approximately 458 million shares and 454 million shares of common stock outstanding, respectively. In addition, Xcel Energy's articles of incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2009 and 2008, 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 $1.5 billion of debt and common equity securities.

NSP-Minnesota has $700 million of debt securities available under its current effective registration statement.

PSCo has approximately $400 million of debt securities available under its currently effective registration statement.

NSP-Wisconsin has $50 million remaining under its currently effective registration statement.

Long-Term BorrowingsSee the Statement of Capitalization and a discussion of the long-term borrowings in Note 6 to the consolidated financial statements.

Financing PlansXcel Energy issues debt securities to refinance retiring maturities, reduce short-term debt, fund construction programs and for other general corporate purposes. Xcel Energy plans to issue the following debt securities in 2010:

Up to $500 million of unsecured debt at the holding company, and

Up to $500 million of first mortgage bonds at NSP-Minnesota.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, interest rates, market conditions and other factors.


Off-Balance-Sheet Arrangements

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


Earnings Guidance

Xcel Energy's 2010 ongoing earnings guidance is $1.55 to $1.65 per share. Key assumptions are detailed below:

Normal weather patterns are experienced for the year.

Weather-adjusted retail electric utility sales grow approximately 1 percent.

Weather-adjusted retail firm natural gas sales decline approximately 1 percent to 2 percent.

Reflects increased revenue due to the full year impact of 2009 electric rate cases in Colorado, Texas and New Mexico, along with the 2010 electric rate increase in Colorado.

Constructive outcomes in the Minnesota natural gas rate and PSCo wholesale electric rate cases.

Increased rider revenue recovery of approximately $30 million.

O&M expenses are projected to increase $115 million to $135 million, or 6 percent to 7 percent.

Depreciation expense is projected to increase by $40 million to $50 million.

Interest expense is projected to increase approximately $15 million to $25 million.

AFUDC-equity is projected to decrease $25 million to $30 million.

The effective tax rate for continuing operations is approximately 34 percent to 36 percent.

Average common stock and equivalents total approximately 460 million shares.

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Item 7A — Quantitative and Qualitative Disclosures About Market Risk

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

Item 8 — Financial Statements and Supplementary Data

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

See Note 21 to the 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, 2009. 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, 2009, 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 herein.

/s/ RICHARD C. KELLY

Richard C. Kelly
Chairman and Chief Executive Officer
February 26, 2010
      /s/ DAVID M. SPARBY

David M. Sparby
Vice President and Chief Financial Officer
February 26, 2010

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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.

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, 2009, 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 26, 2010 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2010

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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, 2009, based on criteria established 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, 2009, 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, 2009 of the Company and our report dated February 26, 2010 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 26, 2010

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

 
  Year Ended Dec. 31  
 
  2009   2008   2007  

Operating revenues

                   
 

Electric

  $ 7,704,723   $ 8,682,993   $ 7,847,992  
 

Natural gas

    1,865,703     2,442,988     2,111,732  
 

Other

    73,877     77,175     74,446  
               
   

Total operating revenues

    9,644,303     11,203,156     10,034,170  

Operating expenses

                   
 

Electric fuel and purchased power

    3,672,490     4,947,979     4,136,994  
 

Cost of natural gas sold and transported

    1,266,440     1,832,699     1,547,622  
 

Cost of sales — other

    22,107     21,082     24,370  
 

Other operating and maintenance expenses

    1,908,097     1,777,933     1,788,885  
 

Conservation and demand side management program expenses

    182,112     117,713     101,772  
 

Depreciation and amortization

    818,052     828,379     805,731  
 

Taxes (other than income taxes)

    306,433     286,580     277,723  
               
   

Total operating expenses

    8,175,731     9,812,365     8,683,097  
               

Operating income

    1,468,572     1,390,791     1,351,073  

Other income, net

    9,771     40,406     9,048  

Equity earnings of unconsolidated subsidiaries

    24,664     3,571     1,900  

Allowance for funds used during construction — equity

    75,686     63,519     37,207  

Interest charges and financing costs

                   
 

Interest charges — includes other financing costs of $20,162, $20,390, and $21,410, respectively

    561,654     552,919     520,037  
 

Interest and penalties related to COLI settlement

            43,401  
 

Allowance for funds used during construction — debt

    (39,799 )   (39,038 )   (34,593 )
               
   

Total interest charges and financing costs

    521,855     513,881     528,845  
               

Income from continuing operations before income taxes

    1,056,838     984,406     870,383  

Income taxes

    371,314     338,686     294,484  
               

Income from continuing operations

    685,524     645,720     575,899  

Income (loss) from discontinued operations, net of tax

    (4,637 )   (166 )   1,449  
               

Net income

    680,887     645,554     577,348  

Dividend requirements on preferred stock

    4,241     4,241     4,241  
               

Earnings available to common shareholders

  $ 676,646   $ 641,313   $ 573,107  
               

Weighted average common shares outstanding:

                   
 

Basic

    456,433     437,054     416,139  
 

Diluted

    457,139     441,813     433,131  

Earnings per average common share — basic:

                   
 

Income from continuing operations

  $ 1.49   $ 1.47   $ 1.38  
 

Loss from discontinued operations

    (0.01 )        
               
   

Earnings per share

  $ 1.48   $ 1.47   $ 1.38  
               

Earnings per average common share — diluted:

                   
 

Income from continuing operations

  $ 1.49   $ 1.46   $ 1.35  
 

Loss from discontinued operations

    (0.01 )        
               
   

Earnings per share

  $ 1.48   $ 1.46   $ 1.35  
               

Cash dividends declared per common share

 
$

0.97
 
$

0.94
 
$

0.91
 

See Notes to Consolidated Financial Statements

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

 
  Year Ended Dec. 31  
 
  2009   2008   2007  

Operating activities

                   

Net income

  $ 680,887   $ 645,554   $ 577,348  

Remove loss (income) from discontinued operations

    4,637     166     (1,449 )

Adjustments to reconcile net income to cash provided by operating activities:

                   
 

Depreciation and amortization

    835,597     843,461     834,455  
 

Conservation and demand side management program expenses

    29,418     39,931     21,442  
 

Nuclear fuel amortization

    80,104     64,203     53,453  
 

Deferred income taxes

    416,581     259,045     265,277  
 

Amortization of investment tax credits

    (6,426 )   (7,198 )   (8,680 )
 

Allowance for equity funds used during construction

    (75,686 )   (63,519 )   (37,207 )
 

Equity earnings of unconsolidated subsidiaries

    (24,664 )   (3,571 )   (1,900 )
 

Dividends from equity method investees

    29,059          
 

Provision for bad debts

    49,023     63,407     57,434  
 

Share-based compensation expense

    29,672     25,511     22,871  
 

Net realized and unrealized hedging and derivative transactions

    39,029     (31,895 )   6,463  
 

Changes in operating assets and liabilities:

                   
   

Accounts receivable

    122,785     (14,108 )   (136,807 )
   

Accrued unbilled revenues

    49,430     (11,520 )   (217,659 )
   

Inventories

    100,504     (135,099 )   (25,464 )
   

Recoverable purchased natural gas and electric energy costs

    (23,901 )   33,947     185,185  
   

Other current assets

    (48,097 )   11,937     (9,922 )
   

Accounts payable

    (50,015 )   28,422     (10,018 )
   

Net regulatory assets and liabilities

    (24,379 )   (70,993 )   27,428  
   

Other current liabilities

    37,701     48,819     52,771  
   

Pension and other employee benefit obligations

    (246,002 )   (104,972 )   (96,930 )
 

Change in other noncurrent assets

    (9,451 )   54,327     3,265  
 

Change in other noncurrent liabilities

    (49,119 )   6,984     (2,168 )

Operating cash flows (used in) provided by discontinued operations

    (28,223 )   (3,323 )   72,346  
               
   

Net cash provided by operating activities

    1,918,464     1,679,516     1,631,534  

Investing activities

                   
 

Utility capital/construction expenditures

    (1,786,902 )   (2,113,246 )   (2,096,857 )
 

Allowance for equity funds used during construction

    75,686     63,519     37,207  
 

Purchase of investments in external decommissioning fund

    (1,644,278 )   (957,752 )   (712,462 )
 

Proceeds from the sale of investments in external decommissioning fund

    1,664,957     914,514     669,070  
 

Investment in WYCO Development LLC

    (42,490 )   (97,924 )   (29,659 )
 

Change in restricted cash

    264     32,008     (9,190 )
 

Cash obtained from consolidation of NMC

            38,950  
 

Other investments

    (1,904 )   2,564     20,832  
               
   

Net cash used in investing activities

    (1,734,667 )   (2,156,317 )   (2,082,109 )

Financing activities

                   
 

Proceeds (repayment) of short-term borrowings, net

    3,750     (633,310 )   462,260  
 

Proceeds from issuance of long-term debt

    689,915     1,915,060     1,162,272  
 

Repayment of long-term debt, including reacquisition premiums

    (621,296 )   (581,313 )   (768,146 )
 

Proceeds from issuance of common stock

    20,133     352,871     10,539  
 

Dividends paid

    (414,922 )   (382,282 )   (378,892 )
 

Early participation payment on debt exchange

            (4,859 )
               
   

Net cash (used in) provided by financing activities

    (322,420 )   671,026     483,174  

Net increase (decrease) in cash and cash equivalents

    (138,623 )   194,225     32,599  

Net increase (decrease) in cash and cash equivalents — discontinued operations

    (2,786 )   3,853     (18,937 )

Cash and cash equivalents at beginning of period

    249,198     51,120     37,458  
               

Cash and cash equivalents at end of period

  $ 107,789   $ 249,198   $ 51,120  
               

Supplemental disclosure of cash flow information:

                   
 

Cash paid for interest (net of amounts capitalized)

  $ (514,675 ) $ (485,373 ) $ (469,142 )
 

Cash received (paid) for income taxes, net

    21,154     (94,744 )   (6,467 )

Supplemental disclosure of non-cash investing transactions:

                   
 

Property, plant and equipment additions in accounts payable

  $ 68,417   $ 55,715   $ 39,681  
 

Storage assets under capital lease

    71,553          

Supplemental disclosure of non-cash financing transactions:

                   
 

Issuance of common stock for reinvested dividends and 401(k) plans

  $ 54,638   $ 56,009   $ 53,105  
 

Issuance of common stock for senior convertible notes

        57,500     229,623  

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
Consolidated Balance Sheets
(amounts in thousands of dollars)

 
  Dec. 31  
 
  2009   2008  

Assets

             

Current assets

             
 

Cash and cash equivalents

  $ 107,789   $ 249,198  
 

Accounts receivable, net

    729,409     900,781  
 

Accrued unbilled revenues

    694,049     743,479  
 

Inventories

    566,205     666,709  
 

Recoverable purchased natural gas and electric energy costs

    56,744     32,843  
 

Derivative instruments valuation

    97,700     101,972  
 

Prepayments and other

    359,560     263,906  
 

Current assets related to discontinued operations

    151,955     56,641  
           
   

Total current assets

    2,763,411     3,015,529  
           

Property, plant and equipment, net

    18,508,296     17,688,720  

Other assets

             
 

Nuclear decommissioning fund and other investments

    1,381,791     1,232,081  
 

Regulatory assets

    2,287,636     2,357,279  
 

Derivative instruments valuation

    289,530     325,688  
 

Other

    140,367     157,742  
 

Noncurrent assets related to discontinued operations

    117,397     181,456  
           
   

Total other assets

    4,216,721     4,254,246  
           
     

Total assets

  $ 25,488,428   $ 24,958,495  
           

Liabilities and Equity

             

Current liabilities

             
 

Current portion of long-term debt

  $ 543,814   $ 558,772