10-K 1 form10k.htm XCEL ENERGY INC 10-K 12-31-2011 form10k.htm


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

FORM 10-K
(Mark One)
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2011
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: 612-330-5500
 
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
$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.  x Yes  o No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  o Yes  x No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  x Yes  o No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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).  xYes  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.  
x 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  x No
 
As of June 30, 2011, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $11,774,380,709 and there were 484,542,416 shares of common stock outstanding.
 
As of Feb. 21, 2012, there were 486,828,501 shares of common stock outstanding, $2.50 par value.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
The Registrant’s Definitive Proxy Statement for its 2012 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
 


 
 

 
 
TABLE OF CONTENTS

Index

PART I
     
Item 1 —
 
3
   
3
   
6
   
8
   
8
   
14
   
15
   
19
   
26
   
27
   
28
   
29
   
30
   
32
   
32
   
33
   
33
   
33
Item 1A —
 
35
Item 1B —
 
43
Item 2 —
 
43
Item 3 —
 
45
Item 4 —
 
46
       
PART II
     
Item 5 —
 
46
Item 6 —
 
49
Item 7 —
 
49
Item 7A —
 
78
Item 8 —
 
78
Item 9 —
 
149
Item 9A —
 
150
Item 9B —
 
150
       
PART III
     
Item 10 —
 
150
Item 11 —
 
150
Item 12 —
 
150
Item 13 —
 
150
Item 14 —
 
150
       
PART IV
     
Item 15 —
 
151
   
162

 
PART I

Item 1 — Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
 
Cheyenne
Cheyenne Light, Fuel and Power Company
Eloigne
Eloigne Company
NCE
New Century Energies, Inc.
NMC
Nuclear Management Company, LLC
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP System
The integrated electric production and transmission system of NSP-Minnesota and NSP-Wisconsin managed by NSP-Minnesota
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
PSCo
Public Service Company of Colorado
PSRI
P.S.R. Investments, Inc.
Seren
Seren Innovations, Inc., a wholly owned subsidiary formerly a broadband communications network
SPS
Southwestern Public Service Co.
UE
Utility Engineering Corporation, an engineering, construction and design company
Utility subsidiaries
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI
WestGas InterState, Inc.
WYCO
WYCO Development LLC
Xcel Energy
Xcel Energy Inc. and its subsidiaries
   
Federal and State Regulatory Agencies
 
ASLB
Atomic Safety and Licensing Board
CPUC
Colorado Public Utilities Commission
DOE
United States Department of Energy
DOER
Division of Energy Resources (formerly the Office of Energy Security)
DOI
United States Department of the Interior
DOT
United States Department of Transportation
EIB
New Mexico Environmental Improvement Board
EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
IRS
Internal Revenue Service
MPCA
Minnesota Pollution Control Agency
MPSC
Michigan Public Service Commission
MPUC
Minnesota Public Utilities Commission
NDPSC
North Dakota Public Service Commission
NERC
North American Electric Reliability Corporation
NMED
New Mexico Environment Department
NMPRC
New Mexico Public Regulation Commission
NRC
Nuclear Regulatory Commission
OCC
Colorado Office of Consumer Counsel
PSCW
Public Service Commission of Wisconsin
PUCT
Public Utility Commission of Texas
SDPUC
South Dakota Public Utilities Commission
SEC
Securities and Exchange Commission
WDNR
Wisconsin Department of Natural Resources

Electric, Purchased Gas and Resource Adjustment Clauses
 
CIP
Conservation improvement program
DSM
Demand side management
DSMCA
Demand side management cost adjustment
ECA
Retail electric commodity adjustment
EECRF
Energy efficiency cost recovery factor
 
 
EIR
Environmental improvement rider
FCA
Fuel clause adjustment
FPPCAC
Fuel and purchased power cost adjustment clause
GAP
Gas affordability program
GCA
Gas cost adjustment
MCR
Mercury cost recovery rider
OATT
Open access transmission tariff
PCCA
Purchased capacity cost adjustment
PCRF
Power cost recovery factor
PGA
Purchased gas adjustment
PSIA
Pipeline system integrity adjustment
QSP
Quality of service plan
RDF
Renewable development fund
RES
Renewable energy standard
RESA
Renewable energy standard adjustment
SCA
Steam cost adjustment
SEP
State energy policy
TCA
Transmission cost adjustment
TCR
Transmission cost recovery adjustment
TCRF
Transmission cost recovery factor

Other Terms and Abbreviations
 
AFUDC
Allowance for funds used during construction
ALJ
Administrative law judge
APBO
Accumulated postretirement benefit obligation
ARC
Aggregator of retail customers
ARO
Asset retirement obligation
ASU
FASB Accounting Standards Update
BART
Best available retrofit technology
CAA
Clean Air Act
CACJA
Clean Air Clean Jobs Act
CAIR
Clean Air Interstate Rule
CapX2020
Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CATR
Clean Air Transport Rule
CCN
Certificate of convenience and necessity
CIPS
Critical Infrastructure Protection Standards
CO2
Carbon dioxide
Codification
FASB Accounting Standards Codification
COLI
Corporate owned life insurance
CON
Certificate of need
CPCN
Certificate of public convenience and necessity
CSAPR
Cross-State Air Pollution Rule
CWIP
Construction work in progress
DSPP
Direct stock purchase plan
EEI
Edison Electric Institute
EGU
Electric generating unit
EPS
Earnings per share
ERRP
Early retiree reimbursement program
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
FTR
Financial transmission right
GAAP
Generally accepted accounting principles
GHG
Greenhouse gas
IFRS
International Financial Reporting Standards
LLW
Low-level radioactive waste
LNG
Liquefied natural gas
MACT
Maximum achievable control technology
MERP
Metropolitan Emissions Reduction Project
 
 
MGP
Manufactured gas plant
MISO
Midwest Independent Transmission System Operator, Inc.
MRO
Midwest Reliability Organization
MVP
Multi-value project
Native load
Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract
NEI
Nuclear Energy Institute
NOL
Net operating loss
NOx
Nitrogen oxide
NOV
Notice of violation
NTC
Notifications to construct
O&M
Operating and maintenance
OCI
Other comprehensive income
PBRP
Performance-based regulatory plan
PCB
Polychlorinated biphenyl
PFS
Private Fuel Storage, LLC
PJM
PJM Interconnection, LLC
PPA
Purchased power agreement
Provident
Provident Life & Accident Insurance Company
PRP
Potentially responsible party
PSP
Performance share plan
PV
Photovoltaic
REC
Renewable energy credit
RECB
Regional expansion criteria benefits
ROE
Return on equity
ROFR
Right of first refusal
RPS
Renewable portfolio standards
RSG
Revenue sufficiency guarantee
RTO
Regional Transmission Organization
SCR
Selective catalytic reduction
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
Standard & Poor’s
Standard & Poor’s Ratings Services
TSR
Total shareholder return
WECC
Western Electricity Coordinating Council
WTMPA
West Texas Municipal Power Agency
   
Measurements
 
Bcf
Billion cubic feet
KV
Kilovolts
KWh
Kilowatt hours
Mcf
Thousand cubic feet
MMBtu
Million British thermal units
MW
Megawatts
MWh
Megawatt hours
 
 
COMPANY OVERVIEW

Xcel Energy Inc. is a holding company with subsidiaries engaged primarily in the utility business.  In 2011, Xcel Energy Inc.’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, and 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 pipelines, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.

Xcel Energy Inc. 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.  The public may read and copy any materials that Xcel Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Xcel Energy’s corporate strategy focuses on three core objectives: obtain stakeholder alignment; invest in our regulated utility businesses; and earn a fair return on our utility investments.  Xcel Energy files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a priority for Xcel Energy and is designed to meet customer and policy maker expectations while creating shareholder value.

NSP-Minnesota

NSP-Minnesota is an operating utility primarily 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 5 percent of its total KWh sold in 2011.  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 2011.  Although NSP-Minnesota’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large commercial and industrial electric sales include customers in the following industries: petroleum and coal, as well as food products.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: real estate and educational services.  Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

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.  Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

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

NSP-Wisconsin is an operating utility primarily 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 KWh sold in 2011.  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 251,000 customers and natural gas utility service to approximately 107,000 customers.  Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2011.  Although NSP-Wisconsin’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large commercial and industrial electric sales include customers in the following industries: food products, paper and allied products, electric and gas, as well as electronics.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: educational services and grocery and dining establishments.  Generally, NSP-Wisconsin’s earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota.

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 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 19 percent of its total KWh sold in 2011.  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 2011.  Although PSCo’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large commercial and industrial electric sales include customers in the following industries: fabricated metal products, as well as electric and gas services.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: real estate and dining establishments.  Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

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

SPS

SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in portions of Texas and New Mexico.  The wholesale customers served by SPS comprised approximately 38 percent of its total KWh sold in 2011.  SPS provides electric utility service to approximately 376,000 retail customers in Texas and New Mexico.  Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2011.  Although SPS’ large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large commercial and industrial electric sales include customers in the oil and gas extraction industry.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: oil and gas extraction and crop related agricultural industries.  Generally, SPS’ earnings contribute approximately 5 percent to 15 percent of Xcel Energy’s consolidated net income.

Other Subsidiaries

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.

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.  The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.
 
 
Xcel Energy Services Inc. is the service company for Xcel Energy Inc.

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

Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other.  See Note 16 to the consolidated financial statements for further discussion relating to comparative segment revenues, income from continuing operations and related financial information.

Seasonality

The demand for electric power generation and natural gas is affected by seasonal differences in the weather.  In general, peak sales of electricity occur in the summer and winter months, and peak sales of natural gas occur in the winter months.  As a result, the overall operating results may fluctuate substantially on a seasonal basis.  Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  See Item 7 — Management’s Discussion of Financial Condition and Results of Operations.

Competition

Xcel Energy’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity.  In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  The FERC has continued to promote competitive wholesale markets through open access transmission and other means.  As a result, Xcel Energy Inc.’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load.  Xcel Energy Inc.’s utility subsidiaries also have franchise agreements with certain cities subject to periodic renewal.  If a city elected not to renew the franchise agreement, it could seek alternative means, such as municipalization.  While each of Xcel Energy Inc.’s utility subsidiaries faces these challenges, their rates are competitive with currently available alternatives.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states.  The MPUC also has regulatory authority over security issuances, property transfers, mergers, dispositions of assets 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 that will be located within the state.  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 generation and transmission facilities, along with 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, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.  NSP-Minnesota has requested continued authorization from the FERC to make wholesale electric sales at market-based prices.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.  NSP-Minnesota is a transmission owning member of the MISO RTO.
 
 
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

 
·
CIP — The CIP recovers the costs of 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.
 
·
RDF — The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.
 
·
RES — The RES is a rider that recovers the costs of new renewable generation.
 
·
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 electric transmission.

NSP-Minnesota has requested that the recovery of the costs associated with the EIR and RES be included in base rates, which is included in the Minnesota electric rate case currently pending approval with the MPUC.

NSP-Minnesota’s retail electric rates 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.  The FCA allows NSP-Minnesota to bill customers for the cost of fuel and 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.

Minnesota state law requires electric utilities to invest 1.5 percent of their state revenues in CIP, except NSP-Minnesota, which is required by law to invest 2 percent.  These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.
 
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 2012, assuming normal weather, is listed below.
 
   
System Peak Demand (in MW)
 
   
2009
   
2010
   
2011
   
2012 Forecast
 
NSP System
     8,615       9,131        9,792       9,213  
 
The peak demand for the NSP System typically occurs in the summer.  The 2011 uninterrupted system peak demand for the NSP System occurred on July 18, 2011.  The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006.

Energy Sources and Related Transmission Initiatives

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

Purchased Power NSP-Minnesota has contracts to purchase power from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased.  NSP-Minnesota also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

Purchased Transmission Services In 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.
 
 
NSP System Resource Plans In December 2011, NSP-Minnesota filed an update to the 2011 through 2025 resource plan with the MPUC.  To account for slower economic growth and the loss of NSP-Wisconsin’s wholesale customers, NSP-Minnesota modified the five-year plan to include a recommendation to withdraw the Black Dog repowering project CON and to reassess the wind procurement plan and resource contingency plan in detail.  The resource plan update also notified the MPUC that there have been changes in the size, timing, and cost estimates for the extended power uprate projects at the Prairie Island nuclear plant.  As a result of these changes, NSP-Minnesota has notified the MPUC that it is completing a new economic and project design analysis and will submit a Change in Circumstances filing seeking reaffirmation of the CON approval before proceeding with the project.  Some elements of the resource plan remain unchanged such as the extension of certain contracts, the Monticello nuclear generating plant extended power uprate project and the commitment to specific CIP program annual achievements.

NSP-Minnesota CapX2020 CON In 2009, the MPUC granted CONs to construct one 230 KV electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four major transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total cost.  The remainder of the costs will be born by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.

NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a CPCN application with the PSCW.  The MPUC has issued route permits for the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project and the Bemidji, Minn. to Grand Rapids, Minn. project.  The remaining required permit activities are on-going in North Dakota, Wisconsin and Minnesota.
 
In December 2011, the Monticello, Minn. to St. Cloud, Minn. project was placed in service and MISO granted the final approval of the Brookings, S.D. project as an MVP.

Black Dog Repowering CON — In March 2011, NSP-Minnesota filed a request with Minnesota regulators to approve a CON for the project to retire its last two coal-burning units (Units 3 and 4) at the Black Dog plant in Burnsville, Minn. and replace them with combined-cycle natural gas burning units.  Units 1 and 2 were converted to natural gas combined-cycle operation in 2002.

In December 2011, NSP-Minnesota requested to withdraw the CON and close the docket.  The request to withdraw is pending an ALJ decision.  NSP-Minnesota will reevaluate the Black Dog repowering project as part of the next resource plan expected in 2013.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of 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 LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah.  If off-site LLW disposal facilities become unavailable, 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.

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.

Nuclear Geologic Repository - Yucca Mountain Project
In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository.  In 2008, the DOE submitted an application to construct a deep geologic repository at this site to the NRC.  In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application.  A number of parties have challenged the DOE’s authority to stop the project and withdraw the application.  The utility industry, including Xcel Energy, is represented in the challenges by the NEI.  In light of the DOE’s plan to stop the project and withdraw its application, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place.  In April 2010, the NEI, on behalf of its members, including Xcel Energy, filed a lawsuit against the DOE in federal court, requesting that the fee be suspended.  The Secretary of Energy has convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel.  On Jan. 26, 2012, the Blue Ribbon Commission report was issued.  The report provides numerous policy recommendations that will be considered by the Secretary of Energy.
 
 
In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application.  In September 2011, the NRC announced that it was evenly divided on whether to take the affirmative action of overturning or upholding the ASLB decision.  Because the NRC could not reach a decision, an order was issued instructing that information associated with the ASLB adjudication should be preserved.  The ASLB complied and the proceeding has been suspended.

Nuclear Spent Fuel Storage
In July 2011, a settlement agreement resolving the method by which NSP-Minnesota can recover certain incremental spent fuel storage costs through 2013 was approved with the DOE.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received a $100 million payment in August 2011, of which $14.5 million was allocated to NSP-Wisconsin.  As of Dec. 31, 2011, NSP-Minnesota has recorded the payment as restricted cash and a regulatory liability.  Additionally, a claim for incremental spent fuel storage costs from 2009-2010 was submitted to the DOE in September 2011 and a claim for 2011 will be submitted to the DOE in May 2012.

NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of Dec. 31, 2011, there were 29 casks loaded and stored at the Prairie Island plant and 10 canisters 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 2006, the U.S. 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 2007, PFS and the Skull Valley Band filed a lawsuit challenging these 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 DOI 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 all domestic reactor sites.

See Note 14 to the consolidated financial statements for further discussion regarding the nuclear generating plants.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear plants.  The event at the nuclear plant in Fukushima, Japan could impact the NRC’s deliberations on NSP-Minnesota’s power uprates discussed below.  This event could also result in additional regulation by the NRC, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force to develop recommendations for NRC consideration on whether it should require immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures and licensing processes.

In July 2011, the task force released its recommendations.  The report confirmed the safety of U.S. nuclear energy facilities and recommends actions to enhance U.S. nuclear plant readiness to safely manage severe events.  In October 2011, the NRC Staff identified the near-term regulatory actions to be taken and prioritized these recommendations into a three-tiered approach.  In December 2011, the NRC Commissioners approved the prioritization of the first tier and second tier recommendations.  The NRC Staff and the industry are working to establish guidance to implement the NRC’s direction regarding resolution of the Tier 1 recommendations and final action by the NRC on these recommendations is expected in the first half of 2012.

The industry is considering a wide range of strategies to address anticipated NRC regulation. Depending on the approach selected, preliminary estimates range from $20 million to $250 million dollars of capital investment approximately over the next five to eight years to address postulated safety upgrades to the Xcel Energy nuclear facilities.  The low end of this range would apply if the NRC accepts the industry’s ‘flex’ approach which provides diverse and portable sources of providing emergency power and water. The high end estimate considers added cost of requiring permanently installed modifications with a higher degree of engineering analysis to meet nuclear standards for flooding, seismic and other local environmental considerations.  Xcel Energy believes the costs of implementing these requirements would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations.

To better coordinate response activities, the U.S. nuclear energy industry has created a steering committee made up of representatives from major electric sector organizations, including Xcel Energy, to integrate and coordinate the industry’s ongoing responses.  In addition, the NRC has conducted technical inspections at Xcel Energy’s nuclear facilities to assess the capability to respond to extraordinary consequences similar to those that occurred at Fukushima, Japan.  These inspections identified no significant findings or issues.
 
 
Nuclear Plant Power Uprates and Life Extension

Life Extensions — In 2006, the NRC renewed the Monticello operating license allowing the plant to operate until 2030.  In June 2011, the NRC issued renewed operating licenses for Prairie Island Units 1 and 2, allowing Unit 1 to operate until 2033 and Unit 2 until 2034.

Monticello Nuclear Plant Extended Power Uprate —  In 2008, NSP-Minnesota filed for both state and federal approvals of an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello nuclear plant.  The MPUC approved the CON for the extended power uprate in 2008.  The filing was placed on hold by the NRC Staff to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  NSP-Minnesota has been working with the industry and regulatory agencies to address this issue and had expected to receive a regulatory decision on the license application in 2012.  In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan’s Fukushima incident are better understood.  NSP-Minnesota is evaluating the impact of this recommendation on the timing of the license decision which will likely result in a delay of the approval.  NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate project during the planned spring 2013 refueling outage.

Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2, which the MPUC approved in 2009.  Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application.  As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.

Total capital investment between 2012 and 2015 for the Monticello and Prairie Island power uprate and life cycle management activities is estimated to be approximately $640 million.

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
 
NSP System Generating Plants
 
Cost
   
Percent
   
Cost
   
Percent
   
Cost
   
Percent
   
Fuel Cost
 
2011
  $ 2.06       55 %   $ 0.89       40 %   $ 6.56       5 %   $  1.82  
2010
    1.89       51       0.83       42       6.29       7       1.73  
2009
    1.78       57       0.70       39       7.36       4       1.61  
* Includes refuse-derived fuel and wood.

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory.  Coal supply inventories at Dec. 31, 2011 and 2010 were approximately 48 and 39 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana.  During 2011 and 2010, coal requirements for the NSP System’s major coal-fired generating plants were approximately 9.5 million tons.  The estimated coal requirements for 2012 are approximately 8 million tons, including adjustments to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator, and exciter systems.  It is uncertain when Sherco Unit 3 will recommence operations.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 99 percent of their coal requirements in 2012, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.  Remaining requirements will be filled through the procurement process or 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 2012 and 2013.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.
 
 
Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification 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 2017 and approximately 66 percent of the requirements for 2018 through 2025.
 
·
Current contracts for conversion services cover 100 percent of the requirements through 2017 and approximately 78 percent of the requirements for 2018 through 2025.
 
·
Current enrichment service contracts cover 100 percent of the requirements through 2016 and approximately 95 percent of the requirements for 2017 through 2025.

Fabrication services for Monticello and Prairie Island are 100 percent committed through 2025 and 2014, respectively.  A contract for fuel fabrication services for Prairie Island is currently being negotiated for 2015 and beyond.

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

Natural gas — The NSP System uses both firm and interruptible natural gas supply 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.  However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market.  Generally, natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC approved transportation tariff rates.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2010, the NSP System’s commitments related to gas supply contracts were $14 million and commitments related to gas transportation and storage contracts were approximately $499 million.  At Dec. 31, 2011, the NSP System did not have any commitments related to gas supply contracts; however, commitments related to gas transportation and storage contracts, which expire in various years from 2012 to 2028, were approximately $462 million.  The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, biomass, solar and hydroelectric power from both owned generating facilities and purchased power agreements. Renewable energy comprised 19.7 percent and 18.3 percent of the NSP System’s total owned and purchased energy for 2011 and 2010, respectively.  Biomass and solar power comprised approximately 2.8 percent and 2.9 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind and hydroelectric sources.  As of Dec. 31, 2011, the NSP System is in compliance with its renewable portfolio standards, which require generation from renewable resources of 15 percent and 8.89 percent of Minnesota and Wisconsin electric retail sales, respectively.

The NSP System also offers customer-focused renewable energy initiatives.  The Windsource® program allows customers in Minnesota and Wisconsin to purchase a portion or all of their electricity from renewable sources.  Approximately 22,715 and 22,676 customers purchased 176,522 MWh and 166,979 MWh of electricity under the Windsource program in 2011 and 2010, respectively.  Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program.  Over 300 PV systems with approximately 3 MW of aggregate capacity and 166 PV systems with approximately 1 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.

Wind  The NSP System acquires the majority of its wind energy from purchased power agreements with wind farm owners, primarily in Southwestern Minnesota.  The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under 1 MW to more than 200 MW.  In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $39 and $37 for 2011 and 2010, respectively.  The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.
 
 
Generally, contracts executed in 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Federal Production Tax Credits in 2012.

The NSP System also fully owns and operates two wind farms.  The 101 MW Grand Meadow Wind Farm began generating electricity in 2008 and the 201 MW Nobles Wind Farm began generating electricity in 2010.  Collectively, the NSP System had over 1,600 MW and nearly 1,500 MW of wind energy on its system at the end of 2011 and 2010, respectively.  Wind energy comprised 9.4 percent and 8.0 percent of the total owned and purchased energy on the NSP System for 2011 and 2010, respectively.

In 2011, NSP-Minnesota agreed to purchase 200 MW of wind power from Geronimo Wind Energy’s Prairie Rose Wind Farm, which is expected to be completed in 2012.  By the end of 2012, the NSP System plans to have over 1,900 MW of wind energy on its system.

Hydroelectric  The NSP System acquires its hydroelectric energy from both owned generation and purchased power agreements.  The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 253 MW of capacity.  For most of 2011, there were eight purchased power agreements in place which provided approximately 24 MW of hydroelectric capacity.  In December 2011, an additional nine MW of purchased hydroelectric capacity was brought onto the system.  Additionally, the NSP System purchases significant generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.  Hydroelectric energy comprised 7.5 percent and 7.4 percent of the total owned and purchased energy on the NSP System for 2011 and 2010, respectively.

Wholesale Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy-related products.  See Item 7 for further discussion.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states.  In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited 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, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.  NSP-Wisconsin has requested continued authorization from the FERC to make wholesale electric sales at market-based prices.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.  NSP-Wisconsin 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.

Fuel and Purchased Energy Cost Recovery Mechanisms NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, under Wisconsin rules, utilities must submit a forward-looking annual fuel cost plan to the PSCW for approval.  Once the PSCW approves the fuel cost plan, utilities must defer the amount of any fuel cost over-collection or under-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW after an opportunity for a hearing.  Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE.  These rules went into effect in January 2011.

NSP-Wisconsin’s wholesale electric rate schedules include a fuel clause adjustment 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, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.
 
 
Wisconsin Energy Efficiency and Conservation Goals In June 2011, the Wisconsin biennial budget bill was signed into law, which rolled back the projected increases for state energy efficiency and conservation funding effective in 2012.  Based on this action, NSP-Wisconsin expects to be allocated approximately $8.2 million of the statewide program costs in 2012, increasing to approximately $9.1 million by 2014.  Historically, NSP-Wisconsin has recovered these costs in rate charges to Wisconsin retail customers and expects to recover the program costs in rates going forward.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See NSP-Minnesota Capacity and Demand.

Energy Sources and Related Transmission Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See NSP-Minnesota Energy Sources and Related Transmission Initiatives.

NSP-Wisconsin CapX2020 CPCN — An application for a CPCN for the Wisconsin portion of the 345 KV CapX2020 project was filed with the PSCW in January 2011.  This line is expected to entail construction of approximately 150 miles of new transmission lines between Hampton, Minn. and La Crosse, Wis. with approximately 50 miles located in Wisconsin at an estimated cost of $200 million to NSP-Wisconsin.

In June 2011, the PSCW determined the application was complete, which triggers the 360-day deadline for the PSCW to grant a CPCN for the project.  In January 2012, the PSCW Staff issued a final Environmental Impact Statement that raises questions about the need for the project and the applicants preferred routes.  There have also been issues raised by the Wisconsin Department of Transportation and the WDNR regarding portions of the proposed route and there are route location alternatives if the PSCW determines these issues warrant such a decision.  Testimony was filed in January and February 2012 and public hearings are expected to be held in March 2012.  The PSCW is expected to issue a final decision in mid-2012 regarding the transmission line.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See NSP-Minnesota Fuel Supply and Costs.

PSCo
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards and natural gas transactions in interstate commerce.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.

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

 
·
ECA — The ECA recovers fuel and purchased power costs.  Short-term sales margins are shared with retail customers through the ECA.  The ECA is revised quarterly.
 
·
PCCA — The PCCA recovers purchased capacity payments.  Effective January 2011, the PCCA began to recover the revenue requirement associated with the purchase of the Blue Spruce Energy Center and Rocky Mountain Energy Center.  Recovery of the revenue requirement for these facilities will be removed from the PCCA to base rates in mid 2012, as part of the PSCo electric rate case.
 
·
SCA — The SCA recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates.  The SCA rate is revised annually in January, as well as on an interim basis to coincide with changes in fuel costs.
 
·
DSMCA — The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.  Beginning 2010, the CPUC approved recovery of the full amount of DSM-related costs through the combination of base rates and a DSMCA tracker mechanism.
 
·
RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2 percent of the customer’s total bill.
 
·
Wind Energy Service — Wind Energy Service is a premium service for those customers who voluntarily choose to pay an additional charge to increase the level of renewable resource generation used to meet the customer’s load requirements.
 
·
TCA — The TCA recovers transmission plant revenue requirements and allows for a return on CWIP outside of rate cases.
 
 
PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC.  PSCo’s wholesale customers have agreed to pay the full cost of renewable energy purchase and generation costs through a fuel clause and in exchange receive renewable energy credits associated with those resources.
 
PBRP and QSP Requirements PSCo currently operates under an electric PBRP.  This regulatory plan includes an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2012.  PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP.  In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP.  The CPUC conducts proceedings to review and approve these rate adjustments annually.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2012, assuming normal weather, is listed below.
 
   
System Peak Demand (in MW)
   
2009
 
2010
 
2011
 
2012 Forecast
PSCo
   
                6,311
   
                6,436
   
                6,896
   
                6,313

The peak demand for PSCo’s system typically occurs in the summer.  The 2011 uninterrupted system peak demand for PSCo occurred on July 18, 2011 and was higher than 2010 and the 2012 forecasted peak demand primarily due to backup load to serve the non-PSCo joint owners of Comanche Unit 3, which was offline when the peak demand occurred.

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 Power PSCo has contracts to purchase power from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased.  PSCo also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

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

PSCo Resource Plan — In October 2011, PSCo filed the 2011 electric resource plan.  Beginning in 2017, PSCo is projected to have relatively low resource needs and has proposed to fill these needs with a competitive resource acquisition process.  The CPUC will consider the resource plan in two phases.  In the first phase, the CPUC will review planning assumptions, competitive bidding structure, and determine if PSCo should acquire generation technology.  The first phase is expected to be completed by the end of 2012.  In the second phase, PSCo will conduct the competitive acquisition process, which is expected to be submitted to the CPUC for approval in 2013.

RES Compliance Plan — Colorado has a law that mandates that at least 30 percent of PSCo’s energy sales be supplied by renewable energy by 2020 and includes a distributed generation standard.  PSCo has filed the 2012 and 2013 RES compliance plan.  PSCo proposed to acquire up to 30 MW of customer-sited solar projects each year and up to 6 MW of community scale solar projects.  A decision on the 2012 and 2013 plan is expected in the first quarter of 2012.  PSCo currently recovers any incentives paid through a combination of the ECA and RESA cost-recovery mechanisms.

Solar*Rewards Program — In March 2011, the CPUC approved a settlement that limits the amount of customer sited solar generation that PSCo will purchase, caps the amount PSCo will spend on customer sited solar generation and shifts from up-front payments to pay-for-performance.  The settlement gives PSCo a presumption of prudence, for both the existing RESA balance, and the future RESA balance if PSCo performs consistent with the acquisition terms of the settlement.

Separately, the CPUC approved a change to the treatment of REC trading margins that allows the customers’ share of the margins through the end of the pilot period, approximately $54 million, to be netted against the RESA regulatory asset balance.  During the second quarter of 2011, PSCo credited approximately $37 million against the RESA regulatory asset balance.
 
 
CACJA — The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal-fired generation identified in the plan.  The plan allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by 2017.  The total investment associated with the adopted plan is approximately $1.0 billion through 2017 and the rate impact is expected to increase future bills on average by 2 percent annually.

In December 2010, the CPUC approved the following:

 
·
Shutdown Cherokee Units 2 and 1 in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);
 
·
Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;
 
·
Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas;
 
·
Shutdown Valmont Unit 5 (186 MW) in 2017;
 
·
Install SCR for controlling NOx and a scrubber for controlling SO2 on Pawnee Generating Station in 2014;
 
·
Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and
 
·
Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

PSCo has received CPCNs for the conversion of Cherokee Unit 2 to a synchronous condenser, for the decommissioning of Cherokee Unit 1 and Unit 2, and for the Pawnee emissions controls.  In addition, PSCo has filed for CPCNs for the new natural gas combined-cycle at Cherokee station and the Hayden emissions controls.

San Luis Valley-Calumet-Comanche Transmission Project In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a 230 KV and 345 KV line and substation construction project.  The line was intended to assist in bringing solar power in the San Luis Valley to customers.  The line was originally expected to be placed in-service in 2013; however, due to delays in the siting and permitting of the line, the in-service date was delayed.

In October 2011, in conjunction with the filing of the electric resource plan, PSCo determined that due to lower projected load growth, lower gas prices and the higher cost of solar thermal generation, it was unlikely to need the transmission line in the foreseeable future.  A CPUC decision on the resource plan is expected in late 2012.

SmartGridCity™ CPCN — As part of the PSCo 2010 electric rate case, the CPUC included recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base.  On July 1, 2011, PSCo implemented an annual rate reduction of $2.8 million.  In December 2011, PSCo filed an application addressing the additional information requested.  A decision is expected in the third quarter of 2012.

Boulder, Colo. Franchise Agreement In November 2011, two ballot measures were passed by the citizens of Boulder.  The first measure increased the occupation tax to raise an additional $1.9 million annually (and extended the tax until the earlier to occur of (1) Dec. 31, 2017, (2) when Boulder decides not to create a municipal utility, or (3) when Boulder commences delivery of municipal electric utility services) for the purpose of funding the exploration costs of forming a municipal utility and acquiring the PSCo electric distribution system in Boulder.  The second measure authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including, but not limited to, the level of initial rates and debt service coverage.  Boulder has retained legal counsel specializing in condemnation and plans to retain legal counsel specializing in FERC matters.  The City Council has not yet decided whether it will proceed with the formation of a municipal electric utility or with commencing a condemnation proceeding.  Should Boulder proceed with these actions and be successful, PSCo would seek to obtain full compensation for the property and business taken by Boulder and for all damages resulting to PSCo and its system.  PSCo would also seek appropriate compensation for stranded costs with the FERC.
 
 
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
 
PSCo Generating Plants
 
Cost
   
Percent
   
Cost
   
Percent
   
Fuel Cost
 
2011
  $ 1.77       76 %   $ 4.98       24 %   $ 2.54  
2010
    1.58       85       5.05       15       2.11  
2009
    1.52       82       3.99       18       1.97  

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal  PSCo normally maintains approximately 41 days of coal inventory.  Coal supply inventories at Dec. 31, 2011 and 2010 were approximately 48 and 34 days usage, respectively.  PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming.  During 2011 and 2010, PSCo’s coal requirements for existing plants were approximately 10.5 and 10.7 million tons, respectively.  The estimated coal requirements for 2012 are approximately 11.6 million tons.

PSCo has contracted for coal supply to provide 100 percent of its coal requirements in 2012, and a declining percentage of requirements in subsequent years.  PSCo’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.  Remaining requirements will be filled through the procurement process or over-the-counter transactions.

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

Natural gas PSCo uses both firm and interruptible natural gas supply 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.  However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market.  The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company, the balance of natural gas supply contracts have pricing features tied to changes in various natural gas indices.  PSCo hedges a portion of that risk through financial instruments.  See Note 11 to the consolidated financial statements for further discussion.  Most transportation contract pricing is based on FERC approved transportation tariff rates.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2010, PSCo’s commitments related to gas supply contracts were approximately $817 million and commitments related to gas transportation and storage contracts were approximately $838 million.  At Dec. 31, 2011, PSCo’s commitments related to gas supply contracts, which expire in various years from 2012 through 2021, were approximately $730 million and commitments related to gas transportation and storage contracts, which expire in various years from 2012 through 2060, were approximately $819 million.

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, biomass, solar, and hydroelectric power from both owned generating facilities and purchased power agreements. Renewable energy comprised 14.6 percent and 11.7 percent of PSCo’s total owned and purchased energy for 2011 and 2010, respectively.  Biomass, solar and hydroelectric power comprised approximately 2.2 percent and 1.4 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind.  As of Dec. 31, 2011, PSCo is in compliance with its renewable portfolio standards which require generation from renewable resources of 12 percent of electric retail sales.
 
PSCo acquires the majority of its wind energy from purchased power agreements with wind farm owners, primarily in Colorado and Wyoming.  PSCo currently has 18 of these agreements in place, with facilities ranging in size from under 3 MW to 300 MW.  In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $45 for each of 2011 and 2010.The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.
 
 
Generally, contracts executed in 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Federal Production Tax Credits in 2012.

In 2011, the new 252 MW Cedar Point Wind Project and the 251 MW Cedar Creek II Wind Farm began commercial operations.  PSCo has long-term purchased power agreements to acquire the output of both facilities.  PSCo has agreed to purchase 200 MW of wind power from NextEra Energy Resources’ Limon Wind Energy Center and an additional 200 MW from NextEra Energy Resources’ Limon Wind Energy Center II, which are both expected to be completed in 2012.  The average cost over the 25 year term of  these contracts is approximately $35 per MWh, which is lower than the average cost per MWh of purchased wind energy on the PSCo system.  By the end of 2012, PSCo plans to have approximately 2,200 MW of wind on its system.

Additionally, PSCo owns and operates the 26.4 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999.  PSCo collectively had nearly 1,800 MW and 1,300 MW of wind energy on its system at the end of 2011 and 2010, respectively.  Wind energy comprised 12.4 percent and 10.3 percent of PSCo’s total owned and purchased energy for 2011 and 2010, respectively.

PSCo also offers customer-focused renewable energy initiatives.  The Windsource program allows customers to purchase a portion or all of their electricity from renewable sources.  Approximately 35,843 and 38,762 customers in Colorado purchased 211,511 MWh and 212,900 MWh of electricity under the Windsource program in 2011 and 2010, respectively.  Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program.  Over 9,600 PV systems with approximately 110 MW of aggregate capacity and over 7,100 PV systems with approximately 76 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.   See Item 7 for further discussion.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states.  The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities.  Each municipality can deny SPS’ rate increase.  SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing.  The NMPRC also has jurisdiction over the issuance of securities.  SPS is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.  SPS has received authorization from the FERC to make wholesale electric sales at market-based prices.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.

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

 
·
FPPCAC — The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.
 
·
EECRF — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.
 
·
TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges.  Effective February 2011, the recovery of the costs associated with the TCRF rider were included in base rates and the TCRF rider was set to zero dollars.
 
·
PCRF — The PCRF rider allows recovery of certain purchased power costs.  Effective February 2011, the recovery of the costs associated with the PCRF rider are included in base rates, and the PCRF rider was eliminated.

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff.  Based on regulatory approval in 2011, SO2 and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor. The regulations allow retail fuel factors to change up to three times per year.
 
 
The fixed fuel and purchased energy recovery factor provides for accounting of over- or under-recovery of fuel and purchased energy expenses.  Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed four percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.  In the fourth quarter of 2011, a fuel surcharge was implemented in Texas for recovery of the under-recovered fuel and purchased energy costs and interest.  The surcharge will remain in place until October 2012.

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, the fuel acquisition and management policies and the 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.

NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC.  The NMPRC reviews SPS’ use of its FPPCAC since the filing of its previous fuel clause continuation filing.  As a follow-up to an SPS rate case, the NMPRC conducted an audit of SPS’ fuel and purchased power costs for a 12-month period from July 2009 through July 2010 and the tracking mechanism to capture costs and revenues associated with SPS’ RECs from assorted wind projects for that period.  In December 2011, the NMPRC authorized SPS to continue its use of its FPPCAC and approved the prudency of the use of the FPPCAC for the period through Dec. 31, 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.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2012, assuming normal weather, is listed below.
 
   
System Peak Demand (in MW)
 
   
2009
 
2010
   
2011
   
2012 Forecast
 
SPS
    5,038       4,985       5,210       5,155  

The peak demand for the SPS system typically occurs in the summer.  The 2011 uninterrupted system peak demand for SPS occurred on Aug. 2, 2011.

Energy Sources and Related Transmission Initiatives

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

Purchased Power SPS has contracts to purchase power from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased.  SPS also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations or to obtain energy at a lower cost.

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

SPS Transmission NTC  In 2010, SPP approved the first of a series of new transmission lines in several states, including Texas, New Mexico and Oklahoma, to help improve electric reliability, strengthen the existing transmission grid and provide outlets for additional renewable wind generation.  As a member of SPP, SPS accepts NTCs for SPP identified lines.  SPS has accepted NTCs for approximately 119 miles of transmission lines at an estimated cost of $126 million.  Under its jurisdiction, the PUCT has thus far approved the construction of two 115 KV and one 230 KV electric transmission line as part of the project at an estimated cost of $29.1 million.  These approved transmission lines are expected to be completed in the first half of 2013.

TUCO to Woodward District Extra High Voltage Interchange — In June 2009, SPP directed SPS to construct a 178 mile 345 KV transmission line between Lubbock, Texas and Woodward, Okla.  The estimated investment in the new line is $184 million and will be recovered from SPP members, including SPS, in accordance with the SPP OATT and the retail ratemaking process.  In March 2011, SPS filed a CCN to build the line with the PUCT.  A decision is expected in the first quarter of 2012.
 
 
Jones CCNIn August 2011, the PUCT approved SPS’ request for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas (Jones Unit 4).  This generating unit will add 168 MW of capacity to the SPS service territory.  In February 2012, the NMPRC approved the CCN.

SPS Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which ten percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2011, increasing to 15 percent in 2015.  SPS primarily fulfills its renewable portfolio requirements through the purchase of wind energy.  In 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 provided that SPS compensates for any shortfall of the 2011 solar energy requirement during 2012 through 2014.  SPS executed and received NMPRC approval for a total of 50 MW of PV solar energy PPAs.  SPS requested and was granted a variance from the NMPRC to extend the time to implement a portion of the diversity requirements to January 2014.  SPS is continuing its efforts to acquire viable biomass generation or make a biogas purchase to meet the diversity  portion of its renewable energy portfolio plan in New Mexico.

SPS solicited public participation throughout 2011 in its New Mexico 2012 Integrated Resource Planning (IRP) and anticipates filing the IRP with the NMPRC in July 2012.

CSAPR — CSAPR addresses long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S.  CSAPR is discussed further at Note 13 to the consolidated financial statements — Environmental Contingencies.  Xcel Energy is in the process of determining various scenarios to respond to the CSAPR depending on whether the CSAPR is upheld, reversed, or modified.

If the CSAPR is upheld and unmodified, Xcel Energy believes that the CSAPR could ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units.  If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls.  The expected cost for these scenarios vary significantly and SPS has estimated capital expenditures of approximately $470 million over the next four years for the CSAPR.

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
 
SPS Generating Plants
 
Cost
   
Percent
   
Cost
   
Percent
   
Fuel Cost
 
2011
  $ 1.89       67 %   $ 4.37       33 %   $ 2.71  
2010
    1.84       71       4.59       29       2.64  
2009
    1.74       73       3.80       27       2.3  

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal  SPS purchases all of the 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.  The coal supply contract with TUCO expires in 2016 and 2017 for the Harrington station and Tolk station, respectively.  As of Dec. 31, 2011 and 2010, coal inventories at SPS were approximately 43 and 41 days supply, respectively.  TUCO has coal agreements to supply 96 percent of SPS’ coal requirements in 2012, and a declining percentage of the requirements in subsequent years.  SPS’ general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.
 
 
Natural gas SPS uses both firm and interruptible natural gas supply 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; which typically is purchased with terms of one year or less.  The transportation and storage contracts expire in various years from 2012 to 2033.  All of the natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates.  These transportation rates are subject to revision based upon FERC or Railroad Commission of Texas approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  SPS’ commitments related to gas supply contracts were approximately $24 million and $28 million and commitments related to gas transportation and storage contracts were approximately $242 million and $233 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind, solar and hydroelectric power from both owned generating facilities and purchased power agreements. Renewable energy comprised 8.2 percent and 7.9 percent of SPS’ total owned and purchased energy for 2011 and 2010, respectively.  Solar and hydroelectric power comprised approximately 0.4 percent and 0.3 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind.  As of Dec. 31, 2011, SPS is in compliance with its renewable portfolio standards, which require generation from renewable resources of approximately 3 percent and 10 percent of Texas and New Mexico electric retail sales, respectively.

SPS acquires its wind energy from long-term purchased power agreements with wind farm owners, primarily in the Texas Panhandle area of Texas and New Mexico.  SPS currently has six of these agreements in place, with facilities ranging in size from under 2 MW to 161 MW.  In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements.  Additionally, SPS is required to purchase another 240 MW of wind energy from qualified generating facilities as defined in the Public Utilities Regulatory Policy Act of 1978.  These purchases are made at the SPP Locational Imbalance Price rather than through long term purchased power agreements.  The average cost per MWh of wind energy under these contracts was approximately $26 and $27 for 2011 and 2010, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.

Generally, contracts executed in 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Federal Production Tax Credits in 2012. At the end of 2011 and 2010, SPS had nearly 700 MW of wind energy on its system.

Additionally, in late 2010, SPS signed an agreement to purchase the output of the 161 MW Spinning Spur Wind Ranch which is expected to be completed in 2012.  Wind energy comprised 7.8 percent and 7.6 percent of SPS’ total owned and purchased energy for 2011 and 2010, respectively.

SPS also offers customer-focused renewable energy initiatives.  The Windsource program allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources.  Approximately 1,233 and 1,224 customers purchased 7,005 MWh and 7,162 MWh of electricity under the Windsource program in 2011 and 2010, respectively.  Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program.  Over 70 PV systems with approximately 5 MW of aggregate capacity and 16 PV systems with less than 1 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.

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 sales and purchases.  See Item 7 for further discussion.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy Inc.’s utility subsidiaries, including enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 12 to the accompanying consolidated financial statements for discussion of other regulatory matters.
 
 
FERC Transmission Planning and Cost Allocation The FERC has approved the open access transmission planning processes for Xcel Energy and the RTOs serving the NSP System and SPS (MISO and SPP, respectively) set forth in tariffs filed in compliance with FERC Order 890.  The FERC has also approved SPP tariffs providing for the partial regional allocation of the cost of new transmission facilities.

In July 2011, the FERC issued Order 1000 adopting modified rules for regional transmission planning, wholesale transmission cost allocation and transmission development.  The new rules would eliminate any preferential right at the federal level for an incumbent transmission provider to construct transmission facilities subject to regional cost allocation, referred to as a ROFR.  The transmission planning processes will be subject to additional tariff revisions subsequent to Order 1000 compliance filings due in October 2012.
 
Order 1000 will require significant changes in transmission planning and cost allocation mechanisms in the WestConnect where PSCo is located.  The impacts of the provisions of Order 1000 regarding transmission planning and cost allocation on SPS and the NSP System are expected to be less significant as they already participate in regional planning and cost allocation processes.  Xcel Energy is in the process of determining the impacts of the new Order 1000 requirements related to future transmission development and ownership.  Irrespective of the new rules, the utility subsidiaries are pursuing several new transmission facility projects.

ARCs In 2009, the FERC adopted rules requiring RTOs to allow ARCs to offer demand response aggregation services to end-use customers of large utilities unless the relevant state regulatory agency prohibited the operation of ARCs.  Under MISO’s proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota.  In 2010, MISO requested its compliance tariff revisions be effective in June 2010, and the MPUC, NDPSC, SDPUC, PSCW, and MPSC all issued orders prohibiting, or temporarily prohibiting, the operation of ARCs in their states.

In January 2011, the MPUC asked public utilities to explore the potential of programs with ARCs that compliment existing CIP initiatives.  In September 2011, NSP-Minnesota agreed to propose a pilot program that would expand existing retail CIP services in a manner analogous to an ARC, but complementary with its existing CIP programs.  NSP-Minnesota is waiting on the MPUC for further guidance prior to proceeding with the pilot program.

In December 2011, the FERC issued orders denying rehearing of the rules and approving most aspects of the MISO compliance filing.  The FERC retained the rules allowing state regulatory authorities to prohibit ARCs within their state.

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

In an order issued in August 2007, the U.S. Court of Appeals remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The U.S. Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued.  The FERC has issued an order on establishing principles for the review proceeding and encouraging a settlement. The settlement process is in progress.

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

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC.  The guidelines established a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation.  Under the guidelines, penalties can range between a minimal amount and $290 million.  The guidelines indicate that the FERC can deviate from the guidelines in its discretion.  The guidelines can apply to any investigation where the FERC Staff has not begun settlement negotiations regarding an alleged violation.
 
 
While Xcel Energy cannot predict the ultimate impact new FERC regulations will have on its results of operations, cash flows or financial position, Xcel Energy continues to take action to comply with existing rules and to implement new FERC rules and regulations as they become effective.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the FERC issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs that could result in material penalties under the FERC penalty guidelines.  The report did not constitute a finding by the FERC.  Xcel Energy disagreed with the preliminary report and demonstrated compliance with applicable standards.  In November 2011, Xcel Energy and SPP filed proposed tariff revisions clarifying the transmission arrangements across the Lamar Tie Line prospectively.

In January 2012, the FERC approved a stipulation and consent agreement in which Xcel Energy did not admit any violations but agreed to pay a $2 million civil penalty.  The FERC contemporaneously issued an order approving changes to the Xcel Energy OATT to allow continued network service arrangements under the tariff.

NERC Compliance Audits and Self-Reports — In 2010 and 2011, the NSP System, PSCo and SPS filed self-reports with the MRO, the WECC and the SPP, respectively, regarding potential violations of certain NERC CIPS.  Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of the utility subsidiaries’ CIPS compliance programs.  Following this comprehensive review, additional self-reports of potential violations were filed.

In 2011, the NSP System was subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS.  The MRO found potential violations of seven standards; five are related to CIPS.  The written MRO audit reports have been issued and referred to MRO’s enforcement function for further action.  None of the potential violations are expected to result in a material penalty.

In May 2011, PSCo was subject to a comprehensive triennial audit by the WECC regarding compliance with various NERC mandatory reliability standards.  In December 2011, PSCo and WECC agreed to a settlement in principle of five violations of four NERC reliability standards, including the two violations self-reported prior to the May 2011 audit.  The violations were all self-identified and self-reported to WECC.  PSCo agreed to pay an immaterial penalty to resolve all five reliability standard violations.  Following execution of the settlement agreement, the agreement must be approved by NERC’s Board of Trustees and filed with FERC for further approval.

In July 2011, SPS filed a self-report with the SPP regarding a potential violation of a NERC reliability standard.  Mitigation actions associated with this self-report are complete, and the violation is not expected to result in a material penalty.
 
NERC Compliance Investigations — In September 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.  In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO.  The final outcome of the compliance investigation, and whether and to what extent penalties for alleged violations may be assessed, is unknown at this time.

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  In February 2011, NERC transferred responsibility for completing the compliance investigation to the MRO.  The MRO reviewed the status of insulating oil levels during the triennial compliance audit in the first quarter 2011.  In July 2011, the NERC issued a preliminary findings report with three potential violations of NERC reliability standards, which NSP-Minnesota responded to in September 2011.  The final outcome of the compliance investigation and whether and to what extent penalties for alleged violations may be assessed is unknown at this time.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions and allowed for affected entities to complete their initial assessment and corrective actions by 2013 and 2014, respectively.  The advisory compliance cost for the utility subsidiaries is estimated at $25 million to $30 million.  Xcel Energy will seek recovery through applicable rate-making mechanisms.
 
 
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 and the FERC approved a two year extension in the second quarter of 2011.  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.

MISO Transmission Pricing — Certain new higher voltage transmission facilities determined by MISO to meet RECB eligibility criteria in the MISO tariff are subject to an allocation of 20 percent of the facility costs to all loads in the 15 state MISO region. Under specific FERC orders, certain new high voltage transmission facilities determined by MISO to meet MVP eligibility criteria are subject to an allocation of 100 percent of the facility costs to all loads on the MISO region.  The MISO independent board of directors must approve MVP eligibility before the costs of a specific project are eligible for regional rate recovery under the MISO tariff.  Certain parties have appealed the FERC MVP tariff orders to the Seventh Circuit Court of Appeals.

The MISO regional cost allocation methods require other customers in MISO to contribute to cost recovery for certain new transmission facilities constructed by the NSP System.  MISO approved the eligibility of the CapX2020 Fargo, N.D. and La Crosse, Wis. transmission expansion projects for 20 percent regional allocation.  In addition, in December 2011, the Brookings, S.D. CapX2020 transmission line was approved by MISO as an MVP, and thus eligible for 100 percent regional cost allocation.  The CapX2020 Bemidji, Minn. transmission expansion project is not eligible for regional cost allocation.  However, the NSP System also pays a share of the costs of projects constructed by other transmission-owning entities in the MISO region found to be eligible for regional cost allocation.  The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation are expected to be material in future periods.  The RECB and MVP cost allocation processes may be subject to future change to comply with FERC Order 1000.

MISO Wholesale Capacity MarketsIn July 2011, MISO filed to implement a resource adequacy tariff to be effective Oct. 1, 2012.  The tariff would establish a MISO capacity market, which would allow the NSP System to purchase or sell short-term capacity in order to comply with regional reliability planning reserve requirements.  The MISO tariff proposal would allow utility capacity arrangements determined through state resource planning processes to be deemed compliant with the tariff.  The tariff proposal is pending FERC action.

Market-Based Rate Rules Each of the Xcel Energy Inc. utility subsidiaries was granted market-based rate authority.  Under market-based rates, the NSP System was reauthorized to sell wholesale power at market-based rates in June 2009.  In December 2011, the NSP System filed for continued market-based rate authority, as required by FERC’s triennial market power review rules effective Jan. 1, 2012.  The request is pending FERC action.  SPS was reauthorized to sell at market-based rate rules outside its service territory by the FERC in 2010.  PSCo was reauthorized to sell at market-based rates outside its service territory in 2011.  Presently, Xcel Energy Inc.’s 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.

RSG Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.  In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants.  MISO has since issued multiple related compliance filings with the FERC.  In recent RSG filings, MISO has proposed to allocate a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants with the loads that benefit from such commitments.  MISO has also proposed to mitigate the offers of resources committed for voltage regulation and local reliability requirements, which is expected to reduce RSG charges to other market participants under the current tariff.  NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms approved by the regulators in each jurisdiction.
 
 
Electric Operating Statistics
 
Electric Sales Statistics
 
   
Year Ended Dec. 31
 
   
2011
   
2010
   
2009
 
Electric sales (Millions of KWh)
                 
Residential
    25,278       25,143       24,039  
Large commercial and industrial
    27,419       27,167       26,647  
Small commercial and industrial
    35,597       35,650       34,608  
Public authorities and other
    1,135       1,100       1,079  
Total retail
    89,429       89,060       86,373  
Sales for resale
    20,177       20,532       21,588  
Total energy sold
    109,606       109,592       107,961  
                         
Number of customers at end of period
                       
Residential
    2,919,660       2,906,248       2,905,105  
Large commercial and industrial
    1,129       1,112       1,100  
Small commercial and industrial
    415,755       413,750       414,603  
Public authorities and other
    69,350       70,413       71,677  
Total retail
    3,405,894       3,391,523       3,392,485  
Wholesale
    78       88       101  
Total customers
    3,405,972       3,391,611       3,392,586  
                         
Electric revenues (Thousands of Dollars)
                       
Residential
  $ 2,712,340     $ 2,622,284     $ 2,355,138  
Large commercial and industrial
    1,616,596       1,533,993       1,422,353  
Small commercial and industrial
    3,025,416       2,956,077       2,649,354  
Public authorities and other
    129,826       126,345       116,933  
Total retail
    7,484,178       7,238,699       6,543,778  
Wholesale
    936,875       960,505       886,417  
Other electric revenues
    345,540       252,641       274,528  
Total electric revenues
  $ 8,766,593     $ 8,451,845     $ 7,704,723  
                         
KWh sales per retail customer
    26,257       26,260       25,460  
Revenue per retail customer
  $ 2,197     $ 2,134     $ 1,929  
Residential revenue per KWh
    10.73 ¢     10.43 ¢     9.80 ¢
Large commercial and industrial revenue per KWh
    5.90       5.65       5.34  
Small commercial and industrial revenue per KWh
    8.50       8.29       7.66  
Wholesale revenue per KWh
    4.64       4.68       4.11  
 
 
Energy Source Statistics
 
   
Year Ended Dec. 31
 
   
2011
   
2010
   
2009
 
   
Millions of
KWh
   
Percent of
Generation
   
Millions of
KWh
   
Percent of
Generation
   
Millions of
KWh
   
Percent of
Generation
 
Coal
    57,014       50 %     57,832       51 %     56,282       50 %
Natural Gas
    25,080       22       25,947       23       27,175       24  
Nuclear
    13,781       12       15,012       13       13,670       12  
Wind (a)
    11,216       10       9,885       9       9,114       8  
Hydroelectric
    4,203       4       3,998       3       5,167       5  
Other (b)
    1,659       2       1,663       1       1,464       1  
Total
    112,953       100 %     114,337       100 %     112,872       100 %
                                                 
Owned generation
    74,722       66 %     77,506       68 %     71,474       63 %
Purchased generation
    38,231       34       36,831       32       41,398       37  
Total
    112,953       100 %     114,337       100 %     112,872       100 %

(a)
This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  Xcel Energy uses RECs to meet or exceed state resource requirements and may sell surplus RECs.
(b)
Includes energy from other sources, including solar, biomass, oil and waste.  Distributed generation from the Solar*Rewards program is not included.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of the utility subsidiaries are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small commercial and industrial (C&I) customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2011, average annual sales to the typical residential customer declined from 96 MMBtu per year to 80 MMBtu per year and to the typical small C&I customer declined from 441 MMBtu per year to 377 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.

Recent Regulatory Development

Pipeline Safety Act The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law on Jan. 3, 2012 (“Pipeline Safety Act”) requires, among other things, additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and/or, if appropriate, develop new regulations, addressing a variety of subjects, including: requiring use of automatic or remote-controlled shut-off valves in certain circumstances; requiring testing of previously untested transmission lines located within high consequence areas operating at a pressure greater than 30 percent of specified minimum yield stress; and expanding integrity management requirements beyond high consequence areas. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2 million for a related series of violations.  While Xcel Energy cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, Xcel Energy is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.
 
 
Public Utility Regulation

Summary of Regulatory Agencies and Areas of JurisdictionRetail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and the NDPSC within their respective states.  The MPUC has regulatory authority over 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.  NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.

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 is 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.

Minnesota state law requires utilities to invest 0.5 percent of their state natural gas revenues in CIP.  These costs are recovered through customer base rates and an annual cost-recovery mechanism for the CIP expenditures.

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 751,985 MMBtu, which occurred on Jan. 20, 2011 and 689,223 MMBtu, which occurred on Dec. 13, 2010.

NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of 587,811 MMBtu per day.  In addition, NSP-Minnesota contracts with providers of underground natural gas storage services.  These 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 31 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 2009-2010, 2010-2011, and 2011-2012 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates.  In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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

2011
  $ 5.25  
2010
    5.43  
2009
    5.78  

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 2012 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, 2011, NSP-Minnesota was committed to approximately $394 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 32 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

See Items 1A and 7 for further discussion of natural gas supply and costs.

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.  NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.  NSP-Wisconsin is subject to the DOT, the PSCW and the MPSC for pipeline safety compliance.

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 NSP-Wisconsin 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.

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 134,636 MMBtu, which occurred on Jan. 20, 2011, and 146,018 MMBtu, which occurred on Dec. 14, 2010.

NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of approximately 133,110 MMBtu per day.  In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services.  These storage agreements provide storage for approximately 27 percent of winter natural gas requirements and 39 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements.  These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 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 2011-2012 supply plan was approved by the PSCW in November 2011.

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:

2011
  $ 5.18  
2010
    5.46  
2009
    5.85  

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 2012 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, 2011, NSP-Wisconsin was committed to approximately $94 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 14 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See Items 1A and 7 for further discussion of natural gas supply and costs.

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.  PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

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

 
·
GCA — The GCA recovers the actual costs of purchased gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in gas rates.  Effective September 2011, the GCA recovers the return on gas in underground storage.
 
·
DSMCA — PSCo has a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.
 
·
PSIA — Effective Jan. 1, 2012, the PSIA began to recover costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines.

QSP Requirements — The CPUC established a natural gas QSP.  This regulatory plan includes a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2012.  The CPUC conducts proceedings to review and approve the rate adjustment annually.

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 1,926,635 MMBtu.  In addition, firm transportation customers hold 565,008 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,491,643 MMBtu per day.  The maximum daily deliveries for PSCo for firm and interruptible services were 2,155,547 MMBtu on Feb. 1, 2011 and 1,820,806 on Jan. 7, 2010.
 
 
PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of approximately 1,847,668 MMBtu per day, which includes 853,453 MMBtu of natural gas held under third-party underground storage agreements.  In addition, PSCo operates three company-owned underground storage facilities, which provide about 22,400 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:

2011
  $ 4.99  
2010
    5.10  
2009
    5.13  

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, 2011, PSCo was committed to approximately $1.1 billion in such obligations under these contracts, which expire in various years from 2012 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 2011, PSCo purchased natural gas from approximately 41 suppliers.

See Items 1A and 7 for further discussion of natural gas supply and costs.

SPS
Natural Gas Facilities Used for Electric Generation

SPS does not provide natural gas service at retail, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines.  SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce; and to the jurisdiction of the DOT and the PUCT for pipeline safety compliance.

See Items 1A and 7 for further discussion of natural gas costs.
 
 
Natural Gas Operating Statistics

   
Year Ended Dec. 31
 
   
2011
   
2010
   
2009
 
Natural gas deliveries (Thousands of MMBtu)
                 
Residential
    139,200       137,809       141,719  
Commercial and industrial
    86,788       87,599       88,943  
Total retail
    225,988       225,408       230,662  
Transportation and other
    117,654       121,261       126,993  
Total deliveries
    343,642       346,669       357,655  
                         
Number of customers at end of period
                       
Residential
    1,747,153       1,735,032       1,723,419  
Commercial and industrial
    153,911       152,937       152,312  
Total retail
    1,901,064       1,887,969       1,875,731  
Transportation and other
    5,395       5,281       4,826  
Total customers
    1,906,459       1,893,250       1,880,557  
                         
Natural gas revenues (Thousands of Dollars)
                       
Residential
  $ 1,133,888     $ 1,115,253     $ 1,159,079  
Commercial and industrial
    601,298       589,449       631,728  
Total retail
    1,735,186       1,704,702       1,790,807  
Transportation and other
    76,740       77,880       74,896  
Total natural gas revenues
  $ 1,811,926     $ 1,782,582     $ 1,865,703  
                         
MMBtu sales per retail customer
    118.87       119.39       122.97  
Revenue per retail customer
  $ 913     $ 903     $ 955  
Residential revenue per MMBtu
    8.15       8.09       8.18  
Commercial and industrial revenue per MMBtu
    6.93       6.73       7.10  
Transportation and other revenue per MMBtu
    0.65       0.64       0.59  

ENVIRONMENTAL MATTERS

Xcel Energy’s facilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.  Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  Xcel Energy’s facilities have been designed and constructed to operate in compliance with applicable environmental standards.  Xcel Energy strives to comply with all environmental regulations applicable to its operations.  However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon Xcel Energy’s operations.  See Item 7 and Notes 12 and 13 to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.  While environmental regulations related to climate change and clean energy continue to evolve, Xcel Energy has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals.  Although the impact of these policies 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.

Xcel Energy is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.  Xcel Energy adopted a methodology for calculating CO2 emissions based on the reporting protocols of The Climate Registry, a nonprofit organization that provides and compiles GHG emissions data from reporting entities.  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 began reporting GHG emissions to the EPA.  Certain REC transactions include a transfer of environmental attributes.  It is not clear whether future GHG reporting regulations could require reporting of CO2 emissions for such REC transfers; current EPA reporting rules do not address REC transactions.
 
 
Based on The Climate Registry’s current reporting protocol, Xcel Energy estimated that its current electric generating portfolio, which includes coal- and gas-fired plants, emitted approximately 59.8 million and 61.7 million tons of CO2 in 2011 and 2010, respectively.  Xcel Energy 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 19.6 million and 19.5 million tons of CO2 in 2011 and 2010, respectively.  Estimated total CO2 emissions, associated with service to Xcel Energy electric customers, decreased by 1.8 million tons in 2011 compared to 2010.  The decrease in emissions was associated with a decrease of 1.4 million MWh of generation.  The average annual decrease in CO2 emissions since 2009 is approximately 3.0 million tons of CO2 per year.

CAPITAL SPENDING AND FINANCING

See Item 7 for a discussion of expected capital expenditures and funding sources.

EMPLOYEES

As of Dec. 31, 2011, Xcel Energy had 11,312 full-time employees, 5,592 of which are covered under collective bargaining agreements.  See Note 9 to the consolidated financial statements for further discussion.


Benjamin G.S. Fowke III, 53, Chairman of the Board, President and Chief Executive Officer, Xcel Energy Inc., August 2011 to present.  Previously, President and Chief Operating Officer, Xcel Energy Inc., August 2009 to August 2011; Executive Vice President and Chief Financial Officer, Xcel Energy Inc., December 2008 to August 2009; Vice President and Chief Financial Officer, Xcel Energy Inc., May 2004 to December 2008; Vice President, Chief Financial Officer and Treasurer, Xcel Energy Inc., October 2003 to May 2004; Vice President and Treasurer, Xcel Energy Inc., November 2002 to October 2003; and Vice President and Chief Financial Officer, Energy Markets Business Unit, Xcel Energy Services Inc., August 2000 to November 2002.

Michael C. Connelly, 50, Senior Vice President, Strategy and Planning, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President and General Counsel, Xcel Energy Inc., June 2007 to September 2011; Vice President of Human Resources, Xcel Energy Services Inc., November 2005 to June 2007; Vice President and Deputy General Counsel, Xcel Energy Services Inc., January 2003 to November 2005; and Deputy General Counsel, Xcel Energy Services Inc., August 2000 to January 2003.

David L. Eves, 53, President, Director and Chief Executive Officer, PSCo, December 2009 to present.  Previously, President, Director and 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 Services Inc., November 2002 to July 2006; and Managing Director, Resource Planning and Acquisition, Xcel Energy Services Inc., August 2000 to November 2002.

Cathy J. Hart, 62, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present and Vice President, Business Services Group, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President, Corporate Services Group, Xcel Energy Services Inc., November 2005 to September 2011.

C. Riley Hill, 52, 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.

Dennis L. Koehl, 56, Senior Vice President and Chief Nuclear Officer, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President and Chief Nuclear Officer, NSP-Minnesota, September 2007 to September 2011; Site Vice President, NMC Point Beach Nuclear Plant, June 2004 to September 2007; Engineering and Site Support Manager, Tennessee Valley Authority, Sequoyah Nuclear Plant, August 2003 to June 2004; and Plant Manager, Tennessee Valley Authority, Sequoyah Nuclear Plant, January 1999 to August 2003.

Kent T. Larson, 52, Senior Vice President, Operations, Xcel Energy Services Inc., September 2011 to present.  Previously, Chief Energy Supply Officer, Xcel Energy Services Inc., March 2010 to September 2011; Vice President, Transmission, Xcel Energy Services Inc., August 2008 to March 2010; Regional Vice President, Xcel Energy Services Inc., February 2006 to August 2008; Vice President, Jurisdictional Relations, Xcel Energy Services Inc., April 2004 to February 2006; and State Vice President, NSP-Minnesota, September 2000 to April 2004.
 
 
Teresa S. Madden, 55, Senior Vice President and Chief Financial Officer, Xcel Energy Inc., September 2011 to present.  Previously, Vice President and Controller, Xcel Energy Inc., January 2004 to September 2011; Vice President of Finance, Customer and Field Operations Business Unit, Xcel Energy Inc., August 2003 to January 2004; Interim Chief Financial Officer, Rogue Wave Software, Inc., February 2003 to July 2003; and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

Marvin E. McDaniel, Jr., 51, Senior Vice President and Chief Administrative Officer, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President and Chief Administrative Officer, Xcel Energy Services Inc., August, 2009 to September 2011 and Vice President, Talent and Technology Business Areas, Xcel Energy Inc., August 2009 to September 2011; 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.

R. Roy Palmer, 53, Senior Vice President, Public Policy and External Affairs, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President, Federal and State Government Affairs, Xcel Energy Services Inc., January 2009 to September 2011; Managing Director, Government and Regulatory Affairs, Xcel Energy Services, Inc., November 2007 to January 2009; Executive Director, State Public Affairs, Xcel Energy Services Inc., April 2005 to November 2007; and Director, Regional Government Affairs, Xcel Energy Services Inc., March 2004 to April 2005.

Judy M. Poferl, 51, President, Director and Chief Executive Officer, NSP-Minnesota, August 2009 to present.  Previously, Regional Vice President, NSP-Minnesota, September 2008 to August 2009; Managing Director, Government and Regulatory Affairs, Xcel Energy Services Inc., November 2007 to September 2008; and Director, Regulatory Administration, Xcel Energy Services Inc., August 2000 to November 2007.

Jeffrey S. Savage, 40, Vice President and Controller, Xcel Energy Inc., September 2011 to present.  Previously, Senior Director, Financial Reporting, Corporate and Technical Accounting, Xcel Energy Services Inc., December 2009 to September 2011; Director, Financial Reporting and Technical Accounting, Xcel Energy Services Inc., March 2007 to December 2009;  and Director, Financial Reporting and Technical Accounting, The Mosaic Company, January 2006 to March 2007.

David M. Sparby, 57, Senior Vice President and Group President, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2009 to September 2011; 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.

Mark E. Stoering, 51, President, Director and Chief Executive Officer, NSP-Wisconsin, January 2012 to present.  Previously, Vice President, Portfolio Strategy and Business Development, Xcel Energy Services Inc., August 2000 to December 2011.

George E. Tyson, II, 46, 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 Services Inc., May 2002 to July 2003; and Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

Scott M. Wilensky, 55, Senior Vice President and General Counsel, Xcel Energy Inc., September 2011 to present.  Previously, Vice President, Regulatory and Resource Planning, Xcel Energy Services Inc., September 2009 to September 2011; Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., August 2008 to September 2009; Executive Director, Revenue, Xcel Energy Services Inc., March 2006 to August 2008; Director, State Public Affairs, Xcel Energy Services Inc., November 2001 to March 2006; Assistant General Counsel, Xcel Energy Services Inc., August 2001 to November 2001; and Senior Attorney, Xcel Energy Services Inc., December 1998 to August 2001.
 
No family relationships exist between any of the executive officers or directors.
 
 
Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process is to understand, manage and, when possible, mitigate material risk.  Xcel Energy management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable.  As described more fully below, Xcel Energy is faced with a number of different types of risk.  Xcel Energy confronts legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for 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.  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 such as 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 in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Xcel Energy management seeks to mitigate the risks inherent in the implementation of Xcel Energy’s strategy.  The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management.  At a threshold level, Xcel Energy has developed a robust compliance program and promotes a culture of compliance, which further mitigates risk.  Building on this culture of compliance, Xcel Energy manages and mitigates risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services.  While 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 management also communicates with the Board and key stakeholders regarding risk.  Xcel Energy provides information to the Board in presentations and communications over the course of the year.  Senior management presents an assessment of key risks to the Board annually.  The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability.  Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s 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.  The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.
 
 
Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2011, 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 PRP 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 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 effect on our results of operations, financial position or cash flows.

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

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

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

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

Increased energy use due to weather changes may require us to invest in additional 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 stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.
 
 
To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods.  To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

Our profitability depends in part on 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.

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 and 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 an 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.

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 purchased 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 Inc. and its subsidiaries credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.  Also, our utility subsidiaries may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy, such as the recent concerns regarding European sovereign debt.  Capital market disruption events, and resulting broad financial market distress, such as the events surrounding the collapse in the U.S. sub-prime mortgage market, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.
 
 
Higher interest rates on short-term borrowings with variable interest rates or on incremental commercial paper issuances could also have an adverse effect on our operating results.  Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning fund and master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily.  The Dodd-Frank Wall Street Reform Act may require broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity.  Also, in October 2010, the FERC finalized its Order 741 rulemaking addressing the credit policies of organized electric markets, such as MISO and SPP.  FERC Order 741 limits the amount of overall credit available to entities operating within organized markets and places restrictions on netting of transactions within organized markets unless certain market protocols are implemented by the RTO.  Various RTOs are in the process of filing their proposed market protocols to satisfy FERC Order 741 and these new market designs may lead to additional margin requirements that could impact our liquidity.

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

We do have additional indirect credit exposures to various domestic and foreign 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 could be in technical default under the contract, which would enable us to exercise our contractual rights.

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

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

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

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

Operational Risks

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

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

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

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 use of radioactive material in the production of energy, the management, handling, storage and disposal of these 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 or a substantial increase in operating expenses at NSP-Minnesota’s nuclear plants.  In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities.  Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
 
 
If an incident did occur, it could have a material 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.  The events at the nuclear plant in Fukushima, Japan could result in increased regulation of the nuclear generation industry as a whole, and additional requirements with respect to emergency planning and demonstrated ability to operate nuclear facilities in the event of natural disasters or other events.  This increased regulation could increase NSP-Minnesota’s compliance costs and impact the results of operations of its nuclear facilities.  Furthermore, these events could cause increased regulatory review and scrutiny by the NRC which could lead to delays in the process for obtaining required regulatory reviews and approvals.

NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota’s production and transmission system, and NSP-Wisconsin may be subject to risks associated with NSP-Minnesota’s nuclear generation.

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

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

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

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

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

Additionally, the cost of potential regulations related to pipeline safety could be significant.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  In 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord and negotiations continue under the United Nations Framework Convention on Climate Change.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.
 
 
The EPA has taken steps to regulate GHGs under the CAA.  In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold.  The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants, although the EPA announced in late September 2011 that this proposed rule will be delayed.

We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 13 to the consolidated financial statements.  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.

There are many uncertainties regarding when and in what form climate change legislation or regulations will be enacted.  The impact of legislation and regulations, 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 recognized as compliance options, 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 U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.
 
We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities.  These include, but are not limited to, rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.
 
Increased risks of regulatory penalties could negatively impact our business.

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

Macroeconomic Risks

Economic conditions could negatively impact our business.

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

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

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies.  Additionally, the cost of those commodities may be higher than expected.
 
 
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material 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 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 comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

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

A 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 impact on our financial condition and results.

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

A cyber incident or cyber security breach could have a material effect on our business.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets could be directly or indirectly affected by unintentional or deliberate cyber incidents.  Cyber intrusion or other similar events could harm our businesses by limiting our generating, transmitting and distributing capabilities or delay our development and construction of new facilities or capital improvement projects to existing facilities.  In addition, as generation and transmission systems as well as natural gas pipelines are part of an interconnected system, a disruption caused by the impact of a cyber security event of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources could also negatively impact our business.  We are unable to quantify the potential impact of such cyber security threats.  These events and corresponding regulatory action, if any, could result in a material decrease in revenues and may cause significant additional costs (e.g., repairs/insurance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite our control environment and security measures, our technology systems may be vulnerable to disability, failures or unauthorized access due to cyber intrusion.  If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting.  In addition, confidential and other data, including sensitive customer or employee information, could be compromised exposing us to liability and business disruption.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.
 
 
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

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

Item 1B — Unresolved Staff Comments

None.

Item 2 — Properties

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

Electric Utility Generating Stations:

NSP-Minnesota
         
Summer 2011
 
           
Net Dependable
 
Station, Location and Unit
 
Fuel
 
Installed
 
 Capability (MW)
 
Steam:
             
A.S. King-Bayport, Minn., 1 Unit
 
Coal
 
1968
 
                       511
 
Sherco-Becker, Minn.
             
Unit 1
 
 Coal
 
1976
 
                       680
 
Unit 2
 
 Coal
 
1977
 
                       682
 
Unit 3
 
 Coal
 
1987
 
                       507
(a)
Monticello-Monticello, Minn., 1 Unit
 
 Nuclear
 
1971
 
                       554
 
Prairie Island-Welch, Minn.
             
Unit 1
 
 Nuclear
 
1973
 
                       521
 
Unit 2
 
 Nuclear
 
1974
 
                       519
 
Black Dog-Burnsville, Minn., 2 Units
 
Coal/Natural Gas
 
1955-1960
 
                       232
 
Various locations, 4 Units
 
 Wood/Refuse-derived fuel
 
Various
 
                         36
(b)
Combustion Turbine:
             
Angus Anson-Sioux Falls, S.D., 3 Units
 
 Natural Gas
 
1994-2005
 
                       338
 
Black Dog-Burnsville, Minn., 2 Units
 
 Natural Gas
 
1987-2002
 
                       236
 
Blue Lake-Shakopee, Minn., 6 Units
 
 Natural Gas
 
1974-2005
 
                       462
 
High Bridge-St. Paul, Minn., 3 Units
 
 Natural Gas
 
2008
 
                       486
 
Inver Hills-Inver Grove Heights, Minn., 6 Units
 
 Natural Gas
 
1972
 
                       282
 
Riverside-Minneapolis, Minn., 3 Units
 
 Natural Gas
 
2009
 
                       470
 
Various locations, 18 Units
 
 Natural Gas
 
Various
 
                       107
 
Wind:
             
Grand Meadow-Mower County, Minn., 67 Units
 
 Wind
 
2008
 
                       101
(c)
Nobles-Nobles County, Minn., 134 Units
 
 Wind
 
2010
 
                       201
(c)
       
 Total
 
                    6,925
 

(a)
Based on NSP-Minnesota’s ownership of 59 percent.  In November 2011, Sherco Unit 3, jointly owned by NSP-Minnesota and Southern Minnesota Municipal Power Agency, experienced a significant failure of its turbine, generator and exciter systems.  See Note 5 to the consolidated financial statements.
(b)
Refuse-derived fuel is made from municipal solid waste.
(c)
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.
 
 
NSP-Wisconsin
           
Summer 2011
 
             
Net Dependable
 
Station, Location and Unit
 
Fuel
 
Installed
   
Capability (MW)
 
Steam:
               
Bay Front-Ashland, Wis., 3 Units
 
 Coal/Wood/Natural Gas
  1948-1956       56  
French Island-La Crosse, Wis., 2 Units
 
 Wood/Refuse-derived fuel
  1940-1948       17  
Combustion Turbine:
                 
Flambeau Station-Park Falls, Wis., 1 Unit
 
 Natural Gas
  1969       13  
French Island-La Crosse, Wis., 2 Units
 
 Natural Gas
  1974       122  
Wheaton-Eau Claire, Wis., 6 Units
 
 Natural Gas
  1973       300  
Hydro:
                 
Various locations, 63 Units
 
 Hydro
 
Various
      135  
       
Total
      643  
 
PSCo
           
Summer 2011
 
             
Net Dependable
 
Station, Location and Unit
 
Fuel
 
Installed
   
Capability (MW)
 
Steam:
               
Arapahoe-Denver, Colo., 2 Units
 
 Coal
  1951-1955       153  
Cherokee-Denver, Colo., 3 Units
 
 Coal
  1957-1968       611
(a)
Comanche-Pueblo, Colo.
                 
Unit 1
 
 Coal
  1973       325  
Unit 2
 
 Coal
  1975       335  
Unit 3
 
 Coal
  2010       511
(b)
Craig-Craig, Colo., 2 Units
 
 Coal
  1979-1980       83
(c)
Hayden-Hayden, Colo., 2 Units
 
 Coal
  1965-1976       237
(d)
Pawnee-Brush, Colo., 1 Unit
 
 Coal
  1981       505  
Valmont-Boulder, Colo., 1 Unit
 
 Coal
  1964       184  
Zuni-Denver, Colo., 1 Unit
 
 Coal
  1948-1954       65  
Combustion Turbine:
                 
Blue Spruce-Aurora, Colo., 2 Units
 
 Natural Gas
  2003       264  
Fort St. Vrain-Platteville, Colo., 6 Units
 
 Natural Gas
  1972-2009       969  
Rocky Mountain-Keenesburg, Colo., 3 Units
 
 Natural Gas
  2004       580  
Various locations, 6 Units
 
 Natural Gas
 
Various
      173  
Hydro:
                 
Cabin Creek-Georgetown, Colo.
                 
Pumped Storage, 2 Units
 
 Hydro
  1967       210  
Various locations, 9 Units
 
 Hydro
 
Various
      26  
Wind:
                 
Ponnequin-Weld County, Colo., 37 Units
 
 Wind
  1999-2001       25
(e)
       
Total
      5,256  

(a)
Cherokee Unit 2 was taken out of service in October 2011.
(b)
Based on PSCo’s ownership interest of 67 percent of Unit 3.
(c)
Based on PSCo’s ownership interest of 10 percent.
(d)
Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.
(e)
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  The on-demand net maximum capacity is based on a company assumption of 12.5 percent dependable generation rate.
 
 
SPS
         
Summer 2011
 
           
Net Dependable
 
Station, Location and Unit
 
Fuel
 
Installed
 
 Capability (MW)
 
Steam:
             
Harrington-Amarillo, Texas, 3 Units
 
Coal
 
1976-1980
 
                    1,018
 
Tolk-Muleshoe, Texas, 2 Units
 
Coal
 
1982-1985
 
                    1,067
 
Cunningham-Hobbs, N.M., 2 Units
 
Natural Gas
 
1957-1965
 
                       254
 
Jones-Lubbock, Texas, 2 Units
 
Natural Gas
 
1971-1974
 
                       486
 
Maddox-Hobbs, N.M., 1 Unit
 
Natural Gas
 
1967
 
                       112
 
Moore County-Amarillo, Texas, 1 Unit
 
Natural Gas
 
1954
 
                         46
 
Nichols-Amarillo, Texas, 3 Units
 
Natural Gas
 
1960-1968
 
                       457
 
Plant X-Earth, Texas, 4 Units
 
Natural Gas
 
1952-1964
 
                       412
 
Combustion Turbine:
             
Carlsbad-Carlsbad, N.M., 1 Unit
 
Natural Gas
 
1968
 
                         10
 
Cunningham-Hobbs, N.M., 2 Units
 
Natural Gas
 
1998
 
                       214
 
Jones-Lubbock, Texas, 1 Unit
 
Natural Gas
 
2011
 
                       171
(a)
Maddox-Hobbs, N.M., 1 Unit
 
Natural Gas
 
1963-1976
 
                         61
 
Riverview-Electric City, Texas, 1 Unit
 
Natural Gas
 
1973
 
                         22
 
       
 Total
 
                    4,330
 

(a)
Construction of Jones Unit 3 was completed in 2011.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2011:

Conductor Miles
 
NSP-Minnesota
   
NSP-Wisconsin
   
PSCo
   
SPS
 
500 KV
    2,917       -       -       -  
345 KV
    6,388       1,152       1,614       6,806  
230 KV
    1,801       -       12,177       9,705  
161 KV
    275       1,548       -       -  
138 KV
    -       -       92       -  
115 KV
    7,691       1,791       4,931       11,216  
Less than 115 KV
    82,706       31,903       73,392       21,486  

Electric utility transmission and distribution substations at Dec. 31, 2011:

   
NSP-Minnesota
   
NSP-Wisconsin
   
PSCo
   
SPS
 
Quantity
    372       204       224       425  

Natural gas utility mains at Dec. 31, 2011:

Miles
 
NSP-Minnesota
   
NSP-Wisconsin
   
PSCo
   
WGI
 
Transmission
    137       -       2,310       11  
Distribution
    9,688       2,231       21,414       -  

Item 3 — Legal Proceedings

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

Additional Information

See Note 13 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Item 1, Item 7 and Note 12 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory matters.
 
 
Item 4 — Mine Safety Disclosures

None.

PART II

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

Quarterly Stock Data

Xcel Energy Inc.’s common stock is listed on the New York Stock Exchange (NYSE).  The trading symbol is XEL.  The number of common shareholders of record as of Dec. 31, 2011 was approximately 76,498.  The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2011 and 2010 and the dividends declared per share during those quarters.

2011
 
High
   
Low
   
Dividends
 
First quarter
  $ 24.67     $ 23.17     $ 0.2525  
Second quarter
    25.39       23.38       0.2600  
Third quarter
    25.60       21.20       0.2600  
Fourth quarter
    27.78       23.48       0.2600  

2010
 
High
   
Low
   
Dividends
 
First quarter
  $ 21.76     $ 19.82     $ 0.2450  
Second quarter
    22.14       19.81       0.2525  
Third quarter
    23.28       20.47       0.2525  
Fourth quarter
    24.36       23.02       0.2525  

Xcel Energy Inc.’s Articles of Incorporation place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding.  On Oct. 31, 2011, Xcel Energy Inc. redeemed all series of its preferred stock.  See Item 7 and Note 4 to the consolidated financial statements for further discussion of Xcel Energy Inc.’s dividend policy.
 
 
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, 2006, and the reinvestment of all dividends).

The EEI Investor-Owned Electrics Index currently includes 55 companies and is a broad measure of industry performance.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Xcel Energy Inc., The EEI Investor-Owned Electrics,
and The S&P 500
 
Graph
 
*
$100 invested on Dec. 31, 2006 in stock and index — including reinvestment of dividends.  Fiscal years ending Dec. 31.

   
2006
   
2007
   
2008
   
2009
   
2010
   
2011
 
Xcel Energy Inc.
  $ 100     $ 102     $ 88     $ 106     $ 123     $ 150  
EEI Investor-Owned Electrics
    100       117       86       96       102       123  
S&P 500
    100       105       66       84       97       99  

Securities Authorized for Issuance Under Equity Compensation Plans

Information required under Item 5 Securities Authorized for Issuance Under Equity Compensation Plans is contained in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.
 
 
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the year ended Dec. 31, 2011:

   
Issuer Purchases of Equity Securities
 
                     
Maximum Number
 
               
Total Number of
   
(or Approximate
 
               
Shares Purchased as
   
Dollar Value) of Shares
 
   
Total Number
         
Part of Publicly
   
That May Yet Be
 
   
of Shares
   
Average Price
   
Announced Plans or
   
Purchased Under the
 
Period
 
Purchased
   
Paid per Share
   
Programs
   
Plans or Programs
 
01/01/11 - 01/31/11 (a)
    16,783     $ 24.00       -       -  
02/01/11 - 02/28/11
    -       -       -       -  
03/01/11 - 03/31/11 (b)
    10,625       23.75       -       -  
04/01/11 - 04/30/11
    -       -       -       -  
05/01/11 - 05/31/11
    -       -       -       -  
06/01/11 - 06/30/11
    -       -       -       -  
07/01/11 - 07/31/11
    -       -       -       -  
08/01/11 - 08/31/11
    -       -       -       -  
09/01/11 - 09/30/11
    -       -       -       -  
10/01/11 - 10/31/11 (c)
    1,049,800       103.11       -       -  
  (d)
    8,500