Edgar Filing: XCEL ENERGY INC

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, 2012

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). x Yes 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, 2012, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $13,843,781,225 and there were 487,285,506 shares of common stock outstanding.

As of Feb. 14, 2013, there were 488,284,020 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2013 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

Index

PART I
Item 1 —	Business	3
	DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
	COMPANY OVERVIEW	6
	ELECTRIC UTILITY OPERATIONS	8
	NSP-Minnesota	8
	NSP-Wisconsin	15
	PSCo	16
	SPS	21
	Electric Operating Statistics	26
	NATURAL GAS UTILITY OPERATIONS	27
	NSP-Minnesota	28
	NSP-Wisconsin	29
	PSCo	30
	Natural Gas Operating Statistics	32
	GENERAL	32
	ENVIRONMENTAL MATTERS	33
	CAPITAL SPENDING AND FINANCING	33
	EMPLOYEES	33
	EXECUTIVE OFFICERS	33
Item 1A —	Risk Factors	35
Item 1B —	Unresolved Staff Comments	43
Item 2 —	Properties	43
Item 3 —	Legal Proceedings	46
Item 4 —	Mine Safety Disclosures	46

PART II
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6 —	Selected Financial Data	48
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	77
Item 8 —	Financial Statements and Supplementary Data	77
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	153
Item 9A —	Controls and Procedures	153
Item 9B —	Other Information	153

PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	153
Item 11 —	Executive Compensation	154
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	154
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	154
Item 14 —	Principal Accountant Fees and Services	154

PART IV
Item 15 —	Exhibits, Financial Statement Schedules	154

SIGNATURES		165

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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
CIG	Colorado Interstate Gas 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.
SPS	Southwestern Public Service Co.
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
CFTC	Commodity Futures Trading Commission
CPUC	Colorado Public Utilities Commission
DOE	United States Department of Energy
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
NMPRC	New Mexico Public Regulation Commission
NRC	Nuclear Regulatory Commission
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
DCRF	Distribution cost recovery factor
DRC	Deferred renewable cost rider
DSM	Demand side management
DSMCA	Demand side management cost adjustment
ECA	Retail electric commodity adjustment
EE	Energy efficiency
EECRF	Energy efficiency cost recovery factor

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EIR	Environmental improvement rider (recovers the costs associated with investments in environmental improvements to fossil fuel generation plants)
EPU	Extended power uprate
FCA	Fuel clause adjustment
FPPCAC	Fuel and purchased power cost adjustment clause
GAP	Gas affordability program
GCA	Gas cost adjustment
OATT	Open access transmission tariff
PCCA	Purchased capacity cost adjustment
PCRF	Power cost recovery factor (recovers the costs of certain purchased power costs)
PGA	Purchased gas adjustment
PSIA	Pipeline system integrity adjustment
QSP	Quality of service plan
RDF	Renewable development fund
RES	Renewable energy standard (recovers the costs of new renewable generation)
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 (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)

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
CCN	Certificate of convenience and necessity
CO2	Carbon dioxide
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
EEI	Edison Electric Institute
EGU	Electric generating unit
EPS	Earnings per share
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
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services

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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
PM	Particulate matter
PPA	Purchased power agreement
Provident	Provident Life & Accident Insurance Company
PRP	Potentially responsible party
PSP	Performance share plan
PTC	Production tax credit
PURPA	Public Utilities Regulatory Policy Act of 1978
PV	Photovoltaic
QF	Qualifying facilities
REC	Renewable energy credit
RFP	Request for proposal
ROE	Return on equity
RPS	Renewable portfolio standards
RSG	Revenue sufficiency guarantee
RSU	Restricted stock unit
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

Measurements
Bcf	Billion cubic feet
GWh	Gigawatt hours
KV	Kilovolts
KWh	Kilowatt hours
Mcf	Thousand cubic feet
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

Xcel Energy Inc. is a holding company with subsidiaries engaged primarily in the utility business. In 2012, 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 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 core priority for Xcel Energy and is designed to meet customer and policy maker expectations for clean energy at a competitive price 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 4 percent of its total KWh sold in 2012. 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 2012. 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, an inactive company.

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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 6 percent of its total KWh sold in 2012. 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 108,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2012. 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: paper and allied products, food products, as well as oil and gas extraction. For small commercial and industrial customers, significant electric retail sales include customers in the following industries: grocery and dining establishments and educational services. 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 13 percent of its total KWh sold in 2012. 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 2012. 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 oil and gas extraction. 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. 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 33 percent of its total KWh sold in 2012. SPS provides electric utility service to approximately 381,000 retail customers in Texas and New Mexico. Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2012. 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 following industries: oil and gas extraction, as well as petroleum and coal products. 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.

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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.

ELECTRIC UTILITY OPERATIONS

NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC 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 been granted continued authorization from the FERC to make wholesale electric sales at market-based prices. 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 improvement projects.

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 recovers the cost 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.

The MPUC approved NSP-Minnesota’s request that the recovery of the costs associated with the EIR and RES be included in base rates in the Minnesota electric rate case as part of the final rates effective Sept. 1, 2012. No costs are being recovered through the EIR at this time. NSP-Minnesota will continue to track PTCs associated with company-owned renewable projects and reflect the difference between the base rate amount and actual costs in the RES adjustment clause.

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 base rates.

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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. NSP-Minnesota was in compliance with this standard in 2012 and expects to be in compliance in 2013. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

CIP Triennial Plan — In October 2012, the Department of Commerce approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent of sales. The combined electric and gas budgets average $104 million per year over the 2013 through 2015 period.

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 2013, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2010		2011		2012		2013 Forecast
NSP System		9,131		9,792		9,475		9,215

The peak demand for the NSP System typically occurs in the summer. The 2012 uninterrupted system peak demand for the NSP System occurred on July 2, 2012. 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. The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions. The forecast for 2013 assumes normal peak day weather and includes the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin. The 2013 forecast also reflects the impact of two large commercial and industrial customers that have ceased operations. These customers represented 0.05 percent of 2012 sales.

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 November 2012, the MPUC issued an order on NSP-Minnesota’s resource plan and required additional filings to determine the next resources needed for the NSP System generating capacity. In December 2012, NSP-Minnesota filed its information indicating an estimated need of 150 MW in 2017 and increasing to 440 MW by 2019, with the size and timing to be determined by the MPUC. A competitive acquisition process is anticipated to commence in March 2013 and result in the selection of a developer or developers by the MPUC in the fourth quarter of 2013. See additional discussion within the Prairie Island Nuclear EPU section below.

CapX2020 — 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 borne by other utilities in the upper Midwest. These cost estimates will be updated as the projects progress.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line

In May 2012, the MPUC issued a route permit for the Minnesota portion of the project. Two parties have filed an appeal with the Minnesota Court of Appeals against the MPUC’s route permit decision. A decision by the Court is anticipated in mid-2013. In May 2012, the PSCW issued a CPCN for the Wisconsin portion of the project. Subsequent legal challenges to the PSCW’s order by intervenors were unsuccessful, thereby rendering the PSCW’s decision final. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

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Monticello, Minn. to Fargo, N.D. 345 KV transmission line

In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service. The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011. The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the portion of the line in North Dakota in September 2012. In January 2013, construction started on the project in North Dakota.

Brookings County, S.D. to Hampton, Minn. 345 KV transmission line

The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011. In June 2011, the SDPUC approved a facility permit for the South Dakota segment. In December 2011, MISO granted the final approval of the project as a MVP. In May 2012, construction started on the project in Minnesota.

Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line

The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.

Black Dog Repowering CON — In November 2012, the MPUC approved the termination of the Black Dog Repowering CON proceeding.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the operations of the nuclear generating plants. The event at the nuclear generating plant in Fukushima, Japan in 2011 could impact the NRC’s deliberations on NSP-Minnesota’s Monticello power uprate request and could also result in additional regulation, which could require additional capital expenditures or operating expenses. The NRC has created an internal task force that has developed recommendations 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 in a written report which recommends actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.

In March 2012, the NRC issued three orders and a request for additional information to all licensees. The orders included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant. The request for additional information included requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant. NSP-Minnesota expects that complying with these requirements will cost approximately $35 to $50 million at the Monticello and Prairie Island plants. Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016. Portions of the work that fall under the requests for additional information are expected to be completed by 2018. NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

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.

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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 approve the withdrawal of the application. 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.

The DOE’s decision and the resulting stoppage of the NRC’s review has prompted multiple legal challenges, including the DOE’s authority to stop the project and withdraw the application, the DOE’s authority to continue to collect the nuclear waste fund fee and the NRC’s authority to stop their review of the DOE’s application. The utility industry, including Xcel Energy, Inc. and NSP-Minnesota, are represented in these challenges by the NEI. Currently, only the challenges to set the nuclear waste fund fee collection rate to zero and seeking the NRC to complete their review remain active and decisions are expected from the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in 2013.

At the time that the DOE decided to stop the Yucca Mountain project and withdraw the application, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel. In January 2012, the Blue Ribbon Commission report was issued. The report provided numerous policy recommendations that are being considered by the Secretary of Energy. In January 2013, the DOE provided its report to Congress relative to their plans to implement the Blue Ribbon Commission’s recommendations including the required legislative changes and authorizations required. The report also announced the Obama Administration's intent to make a pilot consolidated interim storage facility available in 2021, a larger consolidated interim storage facility available in 2025 and a deep geologic repository available in 2048.

Nuclear Spent Fuel Storage

NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. As of Dec. 31, 2012, there were 29 casks loaded and stored at the Prairie Island plant and 10 canisters loaded and stored at the Monticello plant. An additional 35 casks for Prairie Island and 20 canisters for Monticello have been authorized by the State of Minnesota. This currently authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the renewed operating licenses in 2030 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.

PFS — The eight partners of PFS, including NSP-Minnesota, have agreed to dissolve the LLC. PFS filed a letter with the NRC in December 2012 requesting to terminate the PFS license effective immediately. PFS will be taking the appropriate actions to dissolve the LLC in 2013.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD. The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available. The D.C. Circuit remanded the WCD to the NRC and directed it to prepare an environmental impact statement (EIS) if there are significant impacts or an environmental assessment to support a finding of no significant impact. In September 2012, the NRC Commissioners directed the NRC Staff to develop an EIS and a revised WCD and rule on the temporary storage of spent nuclear fuel. The EIS and rule are to be completed within 24 months. NSP-Minnesota does not believe that there will be an immediate impact on operations at the Prairie Island or Monticello nuclear generating plants.

See Notes 13 and 14 to the consolidated financial statements for further discussion regarding nuclear related items.

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 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.

Prairie Island Independent Spent Fuel Storage Installation (ISFSI) License Renewal — The current license to operate an ISFSI at Prairie Island expires in October 2013. An application to renew the ISFSI license for an additional 40 years until 2053 was submitted by NSP-Minnesota to the NRC in October 2011. In August 2012, the Prairie Island Indian Community (PIIC) petitioned to intervene and filed contentions with the NRC. In September 2012, the NRC named an ASLB to review the PIIC’s request to intervene and contentions. In December 2012, the ASLB found that the PIIC had standing to intervene and admitted three of the seven contentions put forward by the PIIC. The ASLB will establish a schedule for the hearing which should be completed by mid-2014. As Prairie Island met the NRC’s criteria for timely renewal by submitting its ISFSI license renewal application more than two years in advance of the expiration of the ISFSI’s current license, it will be allowed to continue to operate under the current license until the NRC has rendered a decision on the license renewal application.

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Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island nuclear generating plant. The total estimated cost of the EPU was $294 million, of which approximately $77.6 million has been incurred, including AFUDC of approximately $13.3 million. Subsequently, NSP-Minnesota filed a resource plan update and a change of circumstances filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages. The information indicated reductions to the estimated benefit of the uprate project. As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers. In December 2012, the MPUC voted unanimously that no party had shown cause to prevent termination of the EPU CON. The MPUC is expected to issue an order terminating the EPU CON in the first half of 2013.

NSP-Minnesota plans to address recovery of incurred costs in the next rate case for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. NSP-Wisconsin plans to seek cost recovery in a future rate case. Based on the outcome of the MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense.

Monticello Nuclear Plant EPU — In 2008, NSP-Minnesota filed for both state and federal approvals of an EPU of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant. The MPUC approved the CON for the EPU in 2008. The license amendment 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. In September 2012, NSP-Minnesota made a supplemental filing to the NRC to address the containment accident pressure concern, as part of its application to amend the operating license to allow the power uprate. NSP-Minnesota expects to receive approval of the EPU project by the NRC in the second half of 2013. NSP-Minnesota is planning to complete implementation of the equipment changes needed to support the Monticello life extension and EPU projects in the planned spring 2013 refueling outage.

Overall, NSP-Minnesota is nearing completion of its life cycle management and EPU project at the Monticello nuclear generating plant to help ensure continued safe and reliable operation through 2030, and to provide additional capacity of approximately 71 MW. As a result of the licensing delays discussed above, as well as engineering design changes and emergent work discovered during implementation, both the cost and the projected in-service date exceed initial estimates, consistent with experience of other nuclear plant life extension and uprate projects. In addition, despite the cancellation of the EPU project at the Prairie Island nuclear generating plant, NSP-Minnesota is implementing life cycle management improvements at the Prairie Island facilities to help ensure their safe and reliable operation through 2034. The major capital investments for these activities at the Monticello and Prairie Island nuclear generating plants are expected to be completed in the years 2013 through 2017, with combined forecasted capital costs in that period of approximately $500 million.

Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
NSP System	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		16,023		35	%		20,131		44	%		19,579		42	%
Nuclear		13,231		29			13,332		29			14,628		31
Natural Gas		6,200		13			3,016		7			3,887		8
Wind (a)		5,443		12			4,312		9			3,760		8
Hydroelectric		3,193		7			3,444		8			3,487		7
Other (b)		1,617		4			1,453		3			1,494		4
Total		45,707		100	%		45,688		100	%		46,835		100	%

Owned generation		31,365		69	%		31,668		69	%		33,758		72	%
Purchased generation		14,342		31			14,020		31			13,077		28
Total		45,707		100	%		45,688		100	%		46,835		100	%

(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs. The NSP System 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 refuse. Distributed generation from the Solar*Rewards program is not included.

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Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned 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 Owned
NSP System Generating Plants		Cost	Percent			Cost	Percent			Cost	Percent			Fuel Cost
2012	$	2.13	47	%	$	0.90	42	%	$	4.21	11	%	$	1.88
2011		2.06	55			0.89	40			6.56	5			1.82
2010		1.89	51			0.83	42			6.29	7			1.73

* 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 41 days of coal inventory. Coal supply inventories at Dec. 31, 2012 and 2011 were approximately 39 and 48 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 2012 and 2011, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.2 million tons and 9.5 million tons, respectively. The estimated coal requirements for 2013 are approximately 8.6 million tons.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 97 percent of their coal requirements in 2013, 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 and 80 percent of their coal requirements in 2013 and 2014, respectively. 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 2018 and approximately 67 percent of the requirements for 2019 through 2025.

Current contracts for conversion services cover 100 percent of the requirements through 2020 and approximately 67 percent of the requirements for 2021 through 2025.

Current enrichment service contracts cover 99.7 percent of the requirements through 2022 and approximately 84 percent of the requirements for 2023 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 certain supply contracts.

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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, 2012 and 2011, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $384 million and $462 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2013 to 2028.

The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2012, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 8.89 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively. Renewable energy comprised 22.0 percent and 19.7 percent of the NSP System’s total owned and purchased energy for 2012 and 2011, respectively. Wind energy comprised 11.9 percent and 9.4 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively. Hydroelectric energy comprised 7.0 percent and 7.5 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively. Biomass and solar power comprised approximately 3.1 percent and 2.8 percent of renewable energy for 2012 and 2011, respectively.

The NSP System also offers customer-focused renewable energy initiatives. Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources. Approximately 24,000 and 23,000 customers purchased 184,000 MWh and 177,000 MWh of electricity under the Windsource program in 2012 and 2011, 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 561 PV systems with approximately 6.7 MW of aggregate capacity and over 300 PV systems with approximately 3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2012 and 2011, respectively.

Wind — The NSP System acquires the majority of its wind energy from PPAs 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 2012, the NSP System began purchasing wind from three new projects, which provided approximately 266 MW of capacity. The largest of these projects, the Prairie Rose Wind Project began commercial operations in December 2012 and the NSP System will purchase the entire output from this 200 MW project. 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 $41 and $39 for 2012 and 2011, 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 2012 benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to the anticipated expiration of the Federal PTCs in 2012. In January 2013, the Federal PTC was extended through 2013.

The NSP System also owns and operates two wind farms. The 101 MW Grand Meadow Wind Farm and the 201 MW Nobles Wind Farm began generating electricity in 2008 and 2010, respectively. Collectively, the NSP System had over 1,870 MW and over 1,600 MW of wind energy on its system at the end of 2012 and 2011, respectively.

Hydroelectric — The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 274 MW of capacity. For most of 2012, there were nine PPAs in place which provided approximately 37 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

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.

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NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited 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 the NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. NSP-Wisconsin and NSP-Minnesota have been granted continued joint authorization from the FERC to make wholesale electric sales at market-based prices. 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 submit a forward-looking annual fuel cost plan to the PSCW for approval. Once the PSCW approves the fuel cost plan, utilities 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.

NSP-Wisconsin’s wholesale electric rate schedules include a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. Effective Jan. 1, 2013, NSP-Wisconsin no longer serves any wholesale municipal electric customers. Rates for wholesale municipal services provided in 2012 will be subject to a formula rate true-up in 2013.

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

Wisconsin 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 was allocated approximately $8.1 million of the statewide program costs in 2012. This amount is expected to increase to approximately $8.6 million by 2014. Historically, NSP-Wisconsin has recovered these costs in rates charged 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 — The PSCW issued a CPCN for the Wisconsin portion of the CapX2020 Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV project in May 2012. The Wisconsin portion consists of approximately 50 miles of new transmission line. The PSCW also approved a route permit and the cost is estimated at $211 million. Subsequent legal challenges to the PSCW’s order by intervenors were unsuccessful, thereby rendering the PSCW’s order final. Construction on the Wisconsin portion of the line is anticipated to begin in 2014 and the line is expected to go into service in 2015.

Fuel Supply and Costs

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

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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 the NERC electric reliability standards and natural gas transactions in interstate commerce.

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

ECA — The ECA 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.

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.

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 certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

PBRP and QSP Requirements — PSCo operates under an electric PBRP. This regulatory plan 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. In July 2012, PSCo filed an application with the CPUC to extend the terms of the current QSP through the end of 2015. PSCo is in settlement discussions and expects resolution in the first quarter of 2013.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2013, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2010		2011		2012		2013 Forecast
PSCo		6,436		6,896		6,689		6,428

The peak demand for PSCo’s system typically occurs in the summer. The 2012 uninterrupted system peak demand for PSCo occurred on June 25, 2012, which was an extremely hot day. The forecasted 2013 system peak is lower than the 2012 peak, primarily due to the assumption of normal weather.

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.

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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 July 2012, PSCo filed two separate applications to update its resource plan. The first was an application to purchase Brush Power, LLC and all of its assets including Brush generating Units 1, 3 and 4 for a total purchase price of approximately $75 million. The Brush units currently provide 237 MW of natural gas fueled capacity and energy to PSCo under PPAs that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.

The second application sought approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013. This was presented as an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas PPA with an existing generator.

In September 2012, the FERC approved the acquisition of Brush Power, LLC. In January 2013, the CPUC denied approval of the acquisition due to the risks associated with the transaction. PSCo has the ability to terminate the transaction pursuant to the terms of the purchase agreement. The CPUC also decided that it was best not to make the decision to retire Arapahoe Unit 4 in this first phase of the resource plan and instead determined that the decision is best made after the retirement can be compared to bids received in the second phase.

RES Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales are supplied by renewable energy by 2020 and includes a distributed generation standard. The CPUC has approved PSCo’s 2012 and 2013 RES compliance plan to acquire up to 30 MW of customer-sited solar projects each year and up to 9 MW of community solar garden projects. The CPUC also approved moving solely to a pay-for-performance basis under the Solar*Rewards distributed solar generation program, which PSCo implemented in June 2012. Based on CPUC approval, PSCo implemented a solar gardens program called Solar*Rewards Community, which will allow customers who either cannot or who prefer not to install solar generation on their property to join together to own interests in a common solar facility and receive a credit related to their share of the solar garden’s electric production on their electric bill. PSCo filled the 9 MW allotted for Solar*Rewards Community in 2012 and will seek to acquire an additional 9 MW in 2013. See Renewable Energy Sources for further discussion.

CACJA — The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx from the coal-fired generation identified in the plan by at least 70 to 80 percent or greater from 2008 levels by 2017. 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. In September 2012, the EPA formally approved the Colorado SIP, including the proposed changes at the PSCo plants.

PSCo’s plan as of Dec. 31, 2012 is as follows:

Cherokee Units 2 and 1 were shut down in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) is expected to be shut down by the end of 2016, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

Cherokee Unit 2 was converted to a synchronous condenser to support the transmission system in 2012;

Fuel switch Cherokee Unit 4 (352 MW) to natural gas by 2017, unless a more cost-effective bid is provided to PSCo in response to the RFP to be issued in Phase 2 of the PSCo Resource Plan in early 2013. If a more cost-effective bid is obtained, then Cherokee Unit 4 would be retired at the end of 2017;

Shutdown Arapahoe Unit 3 (45 MW) at the end of 2013;

Fuel Switch Arapahoe Unit 4 (111 MW) at the end of 2013, unless a more cost-effective bid is provided to PSCo in response to the RFP to be issued in Phase 2 of the PSCo Resource Plan in early 2013. If a more cost effective bid is obtained, then Arapahoe Unit 4 would be retired at the end of 2013;

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; and

Install SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016.

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PSCo has received CPCNs for the following:

Conversion of Cherokee Unit 2 to a synchronous condenser;

Decommissioning of Cherokee Unit 1 and Unit 2;

Installing Pawnee emissions controls;

Installing SCRs on the Hayden units;

Shutdown Arapahoe 3 at the end of 2013; and

Constructing a new natural gas combined-cycle unit at Cherokee Station.

PSCo is in the process of decommissioning Cherokee Units 1 and 2.

Steam System Package Boilers and Regulatory Plan — In December 2012, PSCo filed for a CPCN to construct two packaged boilers for its steam utility. The application also sought approval for PSCo’s regulatory plan affecting rates for natural gas and steam services effective after the boilers have been placed in service. The proposed regulatory plan would combine the gas and steam revenue requirements for purposes of setting rates for retail gas and steam customers beginning January 2016. PSCo estimates that the impact of its proposed regulatory plan will be a reduction in the revenue requirement for steam of approximately $3.2 million and a corresponding $3.2 million increase in the revenue requirement for natural gas. A CPUC decision is expected in late 2013.

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. In March 2011, the CPUC granted a CPCN for this project. The CPUC’s decisions have been appealed to the Costilla County District Court by Blanca Ranch Holdings, LLC and Trinchera Ranch Holdings, LLC, and are pending before the Court.

In October 2011, 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. PSCo is awaiting a final Phase I decision in its 2011 resource plan before making a final determination. A CPUC decision on the resource plan is anticipated in the first quarter of 2013.

SmartGridCity™ (SGC) Cost Recovery — PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case. In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs. In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC and also provided the additional information requested. On Jan. 17, 2013, the ALJ recommended denial of PSCo’s request for recovery of the remaining portion of the SGC investment. On Feb. 6, 2013, PSCo filed exceptions to the ALJ recommendation requesting that the CPUC grant recovery of its investment. However, as a result of the ALJ’s recommended decision denying recovery, PSCo recognized a $10.7 million pre-tax charge in 2012, representing the net book value of the disallowed investment, which is included in O&M expense.

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 for a limited duration with the stated 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 the level of initial rates and debt service coverage. Boulder has retained multiple legal firms that specialize in condemnation and FERC matters, as well as several other consultants.

The City Council has not yet decided whether it will proceed with the formation of a municipal electric utility or with the commencement of a condemnation or FERC stranded cost proceeding. In December 2012, Boulder issued a white paper exploring opportunities for reaching its energy goals with PSCo, in lieu of condemnation. PSCo has advised Boulder that it is willing to discuss many of these opportunities. Boulder has announced that the City Council will decide whether to proceed with the formation of a municipal electric utility in April 2013. Should Boulder attempt to condemn PSCo facilities, 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.

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Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		21,367		59	%		22,065		61	%		22,767		61	%
Natural Gas		7,930		22			8,896		24			9,854		27
Wind (a)		5,752		16			4,518		12			3,830		10
Hydroelectric		590		2			681		2			446		1
Other (b)		263		1			324		1			257		1
Total		35,902		100	%		36,484		100	%		37,154		100	%

Owned generation		23,766		66	%		23,743		65	%		24,444		66	%
Purchased generation		12,136		34			12,741		35			12,710		34
Total		35,902		100	%		36,484		100	%		37,154		100	%

(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including nuclear, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included.

Fuel Supply and Costs

	Coal					Natural Gas						Weighted Average Owned
PSCo Generating Plants	Cost		Percent			Cost			Percent			Fuel Cost
2012	$	1.77		78	%		$	4.25		22	%		$	2.31
2011		1.77		76				4.98		24				2.54
2010		1.58		85				5.05		15				2.11

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, 2012 and 2011 were approximately 46 and 48 days usage, respectively. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2012 and 2011, PSCo’s coal requirements for existing plants were approximately 11.3 and 10.5 million tons, respectively. The estimated coal requirements for 2013 are approximately 11.4 million tons.

PSCo has contracted for coal supply to provide 97 percent of its coal requirements in 2013, 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 and 46 percent of its coal requirements in 2013 and 2014, respectively. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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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, 2012, PSCo’s commitments related to gas supply contracts, which expire in various years from 2013 through 2023, were approximately $1.1 billion and commitments related to gas transportation and storage contracts, which expire in various years from 2013 through 2060, were approximately $754 million. At Dec. 31, 2011, PSCo’s commitments related to gas supply contracts were approximately $730 million and commitments related to gas transportation and storage contracts were approximately $819 million.

PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2012, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 12 percent of electric retail sales. Renewable energy comprised 18.7 percent and 14.6 percent of PSCo’s total owned and purchased energy for 2012 and 2011, respectively. Wind energy comprised 16.0 percent and 12.4 percent of PSCo’s total owned and purchased energy for 2012 and 2011, respectively. Hydroelectric, biomass and solar power comprised approximately 2.7 percent and 2.2 percent of renewable energy for 2012 and 2011.

PSCo also offers customer-focused renewable energy initiatives. Windsource, one of the nation’s largest voluntary renewable energy programs, allows customers to purchase a portion or all of their electricity from renewable sources. Approximately 34,000 and 36,000 customers in Colorado purchased 201,000 MWh and 212,000 MWh of electricity under the Windsource program in 2012 and 2011, 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 12,500 PV systems with approximately 138 MW of aggregate capacity and over 9,600 PV systems with approximately 110 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2012 and 2011, respectively.

PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily in Colorado and Wyoming. PSCo currently has 19 of these agreements in place, with facilities ranging in size from 2 MW to over 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 $47 and $45 for 2012 and 2011, 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 2012 benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to the anticipated expiration of the Federal PTCs in 2012. In January 2013, the Federal PTC was extended through 2013.

In November 2012, the 200 MW Limon Wind Energy Center and 200 MW Limon Wind Energy Center II began commercial operations. PSCo has long-term PPAs to acquire the output of both facilities. The average cost over the 25 year term of the Limon II contract is approximately $35 per MWh, which is lower than the average cost per MWh of purchased wind energy on the PSCo system.

Additionally, PSCo owns and operates the 26 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999. PSCo collectively had approximately 2,200 MW and 1,800 MW of wind energy on its system at the end of 2012 and 2011, 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.

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SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. Each municipality can deny SPS’ rate increases. 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.

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

DCRF — The DCRF rider recovers distribution costs in Texas.

DRC — The DRC rider recovers deferred costs associated with renewable energy programs in New Mexico. The current rider is in effect through June 2013.

EECRF — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.

EE rider — The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.

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.

PCRF — The PCRF rider allows recovery of certain purchased power costs in Texas.

TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas.

The PUCT approved SPS’ request that the recovery of the costs associated with the TCRF and PCRF be included in base rates effective February 2011. 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 the 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.

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

NMPRC regulations require SPS to request authority to continue collecting its fuel and purchased power costs through a fuel adjustment clause every 4 years. The NMPRC has granted SPS authority to use a fuel adjustment clause through November 2014.

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 2013, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2010		2011		2012		2013 Forecast
SPS		4,985		5,210		5,265		5,193

The peak demand for the SPS system typically occurs in the summer. The 2012 uninterrupted system peak demand for SPS occurred on Aug. 2, 2012.

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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 — As a member of SPP, SPS accepts NTCs for projects identified through SPP’s reliability planning process, transmission service, generator interconnection study process, economic study process or the load addition process. These are all new electric transmission projects and are typically a portfolio of transmission lines and electric substation projects. SPS has accepted NTCs for several hundred miles of transmission line and substations at an estimated capital cost of approximately $800 million. These projects span several years to plan, site, procure and develop. Typical SPS capital spending for SPP NTC transmission projects is approximately $150 to $200 million per year, but may vary. Under their jurisdictions, the NMPRC and PUCT have approved the siting and routing of all SPP identified transmission line NTC projects that have been presented. Projects identified through SPP NTCs may have costs allocated to other SPP members in accordance with SPP policies. Costs allocated to SPS are permissible for recovery through NMPRC, PUCT and FERC processes.

TUCO Inc. (TUCO) to Woodward 345 KV transmission line

The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line. This line connects the major TUCO substation near Lubbock, Texas with the Oklahoma Gas & Electric (OGE) substation in Woodward, Okla. SPS is constructing the line to just inside the Oklahoma state line, and OGE is building from there to Woodward. SPS’ estimated investment in the TUCO to Woodward line and substation is $185 million and is expected to be recovered from SPP members in accordance with the SPP OATT and the ratemaking process. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in 2014.

Hitchland to Woodward 345 KV transmission line

The Hitchland to Woodward line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle. SPS is building the first 30 miles from Hitchland towards Woodward and OGE is completing the line from there to Woodward. SPS’ estimated investment for the Hitchland to Woodward line and substation is $56 million and is expected to be recovered from SPP members in accordance with the SPP OATT and the ratemaking process.

Jones CCN — In 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 with a projected cost of $118 million, inclusive of AFUDC. Jones Unit 4 is expected to reach commercial operation in the second quarter of 2013.

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). SPS made the IRP filing with NMPRC in July 2012, which was accepted without modification in September 2012.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S. In August 2012, the D.C. Circuit issued an opinion that vacated the CSAPR, but required continued implementation of the CAIR pending the EPA’s development of a replacement program. CSAPR and CAIR are discussed further at Note 13 to the consolidated financial statements — Environmental Contingencies.

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Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		14,005		49	%		14,818		48	%		15,486		51	%
Natural Gas		12,088		43			13,167		43			12,206		40
Wind (a)		2,103		7			2,386		8			2,295		8
Other (b)		177		1			409		1			361		1
Total		28,373		100	%		30,780		100	%		30,348		100	%

Owned generation		19,940		70	%		19,310		63	%		19,303		64	%
Purchased generation		8,433		30			11,470		37			11,045		36
Total		28,373		100	%		30,780		100	%		30,348		100	%

(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs. SPS uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included.

Fuel Supply and Costs

		Coal				Natural Gas				Weighted Average Owned
SPS Generating Plants		Cost	Percent			Cost	Percent			Fuel Cost
2012	$	1.87	67	%	$	2.99	33	%	$	2.24
2011		1.89	67			4.37	33			2.71
2010		1.84	71			4.59	29			2.64

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. 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, 2012 and 2011, coal inventories at SPS were approximately 40 and 43 days supply, respectively. TUCO has coal agreements to supply 92 percent of SPS’ coal requirements in 2013, 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 2013 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. 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 $57 million and $24 million and commitments related to gas transportation and storage contracts were approximately $229 million and $242 million at Dec. 31, 2012 and 2011, respectively.

SPS has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

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Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2012, SPS is in compliance with mandated RPS, which require generation from renewable resources of approximately 4 percent and 10 percent of Texas and New Mexico electric retail sales, respectively. Renewable energy comprised 7.9 percent and 8.2 percent of SPS’ total owned and purchased energy for 2012 and 2011, respectively. Wind energy comprised 7.4 percent and 7.8 percent of SPS’ total owned and purchased energy for 2012 and 2011, respectively. Solar power comprised approximately 0.5 percent and 0.4 percent of renewable energy for 2012 and 2011, respectively.

SPS also offers customer-focused renewable energy initiatives. Windsource, one of the nation’s largest voluntary renewable energy programs, allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources. Approximately 1,100 and 1,200 customers purchased 5,000 MWh and 7,000 MWh of electricity under the Windsource program in 2012 and 2011, respectively. Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program. Over 80 PV systems with approximately 4.5 MW of aggregate capacity and over 70 PV systems with approximately 5 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2012 and 2011, respectively.

SPS acquires its wind energy from long-term PPAs 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 for a total capacity greater than 600 MW. In late 2012, the 161 MW Spinning Spur Wind Ranch began commercial operations. SPS will purchase the entire output of this 161 MW facility. 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 currently purchasing an additional 250 MW of wind energy from qualified generating facilities, as defined in the PURPA. The average cost per MWh of wind energy under the PPA and QF contracts was approximately $26 for each of 2012 and 2011. 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 2012 benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to the anticipated expiration of the Federal PTCs in 2012. In January 2013, the Federal PTC was extended through 2013. At the end of 2012 and 2011, SPS had nearly 860 MW and 700 MW of wind energy on its system, 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 a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —The FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. The requirements for transmission planning and cost allocation were addressed by revisions to the MISO Tariff for NSP-Minnesota and NSP-Wisconsin as discussed below in MISO Transmission Pricing; and Xcel Energy expects the requirements will be addressed by revisions to the SPP Tariff for SPS. PSCo submitted its compliance filing in October 2012, proposing to comply through participation in WestConnect, a consortium of utilities in the Western Interconnection. The filing is pending FERC action.

In 2012, Minnesota’s Governor signed legislation that preserves the rights of incumbent utilities to construct and own transmission interconnected to their systems. This legislation is similar to legislation previously passed in North Dakota and South Dakota. Therefore, Order 1000 is expected to have limited impacts on future transmission development and ownership in the NSP System in Minnesota, North Dakota and South Dakota. For the Wisconsin portion of the NSP System, the impacts of the new requirements relating to future transmission development and ownership are uncertain.

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Furthermore, in Texas, the issue of whether incumbent utilities have the rights to construct and own transmission interconnected to their system is disputed by some parties in SPP. Xcel Energy believes that state statutes protect the right of incumbent utilities to construct and own transmission interconnected to their systems, and does not expect that this aspect of Order 1000 will impact the portion of SPS in Texas. However, the portion of SPS in New Mexico and PSCo may be impacted by the provisions of Order 1000 relating to an incumbent’s right to build transmission because neither New Mexico nor Colorado has legislation protecting the rights of utilities to develop transmission projects in their service areas.

Xcel Energy Services Inc. and NSP-Wisconsin vs. ATC (La Crosse, Wis. to Madison, Wis. Transmission Line) — In February 2012, Xcel Energy Services Inc. and NSP-Wisconsin filed a complaint with the FERC concerning ownership of the proposed La Crosse, Wis. to Madison, Wis. 345 KV transmission line. In July 2012, the FERC granted Xcel Energy Services Inc.’s and NSP-Wisconsin’s complaint, ruling that the responsibilities to construct the La Crosse, Wis. to Madison, Wis. transmission line belong equally to both parties. In August 2012, American Transmission Company LLC (ATC) requested rehearing and requested that the FERC grant a stay of the ruling. In September 2012, the FERC granted rehearing for purposes of further consideration but did not grant a stay. Thus, the July ruling remains in effect pending the FERC’s further ruling on rehearing. In order to proceed with development of the project, the two companies are working together on routing and regulatory state issues pending FERC action on ATC’s request for rehearing. In addition, ITC Midwest LLC filed a similar complaint against ATC with the FERC concerning ownership of the Dubuque, Iowa to Cardinal (Madison, Wis.) line, a 136 mile, 345 KV transmission line that is also a MISO MVP project and that connects in Madison, Wis. to the La Crosse, Wis. to Madison, Wis. line. In February 2013, the FERC granted the ITC Midwest complaint.

ATC vs. Xcel Energy Services Inc. and MISO (Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. Transmission Line) — In October 2012, ATC filed a complaint against MISO, Xcel Energy Services Inc., NSP-Minnesota and NSP-Wisconsin, alleging that, under the legal principles set forth in the July 2012 FERC ruling in the La Crosse to Madison transmission line complaint filed by Xcel Energy Services Inc. on behalf of its subsidiary NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton to Rochester to La Crosse CapX2020 line and the La Crosse to Madison line as a single facility under the MISO Transmission Owners Agreement and Tariff. Thus, ATC should have been designated as the owner of the La Crosse to Madison line portion of the purported single facility. Xcel Energy filed an answer seeking dismissal of the ATC complaint in October 2012. On Feb. 4, 2013, the FERC issued an order denying the ATC complaint. The FERC found that MISO properly applied its planning process and that Hampton to La Crosse and the La Crosse to Madison lines are separate. Therefore, MISO’s prior ownership decisions stand.

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 and NSP-Wisconsin. 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 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. NSP-Minnesota is exploring a pilot program that would expand existing retail CIP services to more fully interact with the MISO market. The most recent filing in this open docket was in November 2012.

Electric Transmission Rate Regulation — The FERC regulates the rates 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 considered an RTO.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments: some lower voltage projects are fully allocated to loads near the project vicinity, and other reliability projects are allocated 20 percent regionally and 80 percent to local loads. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to provide multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving. Certain parties have appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit.

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In its Order 1000 compliance filing in October 2012, MISO proposed that all future reliability projects be fully allocated to the zones in which the project is located (rather than allocating costs more broadly) while MVP projects would continue to be eligible for regional cost allocation. FERC action is anticipated in 2013. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery. Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities. 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 could be significant in future periods.

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. In recent RSG filings, MISO has proposed, and the FERC has accepted, allocating 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. NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms approved by the regulators in each jurisdiction. Certain of the FERC’s orders remain pending on rehearing, and appeals of the FERC orders to the U.S. Court of Appeals for the D.C. Circuit have been held in abeyance, pending the FERC’s disposition of rehearing requests.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2012			2011			2010
Electric sales (Millions of KWh)
Residential		25,033			25,278			25,143
Large commercial and industrial		27,396			27,419			27,167
Small commercial and industrial		35,660			35,597			35,650
Public authorities and other		1,109			1,135			1,100
Total retail		89,198			89,429			89,060
Sales for resale		15,781			20,177			20,532
Total energy sold		104,979			109,606			109,592

Number of customers at end of period
Residential		2,940,024			2,919,660			2,906,248
Large commercial and industrial		1,147			1,129			1,112
Small commercial and industrial		419,618			415,755			413,750
Public authorities and other		68,510			69,350			70,413
Total retail		3,429,299			3,405,894			3,391,523
Wholesale		75			78			88
Total customers		3,429,374			3,405,972			3,391,611

Electric revenues (Thousands of Dollars)
Residential	$	2,713,575		$	2,712,340		$	2,622,284
Large commercial and industrial		1,534,728			1,616,596			1,533,993
Small commercial and industrial		3,023,154			3,025,416			2,956,077
Public authorities and other		130,538			129,826			126,345
Total retail		7,401,995			7,484,178			7,238,699
Wholesale		687,912			936,875			960,505
Other electric revenues		427,389			345,540			252,641
Total electric revenues	$	8,517,296		$	8,766,593		$	8,451,845

KWh sales per retail customer		26,011			26,257			26,260
Revenue per retail customer	$	2,158		$	2,197		$	2,134
Residential revenue per KWh		10.84	¢		10.73	¢		10.43	¢
Large commercial and industrial revenue per KWh		5.60			5.90			5.65
Small commercial and industrial revenue per KWh		8.48			8.50			8.29
Wholesale revenue per KWh		4.36			4.64			4.68

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Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		51,395		47	%		57,014		50	%		57,832		51	%
Natural Gas		26,218		24			25,080		22			25,947		23
Wind (a)		13,298		12			11,216		10			9,885		9
Nuclear		13,249		12			13,781		12			15,012		13
Hydroelectric		3,800		3			4,203		4			3,998		3
Other (b)		2,022		2			1,659		2			1,663		1
Total		109,982		100	%		112,953		100	%		114,337		100	%

Owned generation		75,071		68	%		74,722		66	%		77,506		68	%
Purchased generation		34,911		32			38,231		34			36,831		32
Total		109,982		100	%		112,953		100	%		114,337		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 refuse. 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 2012, average annual sales to the typical residential customer declined from 96 MMBtu per year to 78 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.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires, among other things, additional verification of pipeline infrastructure records by 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. This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and 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 certain previously untested transmission lines; and expanding integrity management requirements. 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. PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider.

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NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail 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 Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation service and storage service. 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 732,135 MMBtu, which occurred on Jan. 19, 2012 and 751,985 MMBtu, which occurred on Jan. 20, 2011.

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 590,698 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, 2011-2012, and 2012-2013 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.

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:

2012	$	4.41
2011		5.25
2010		5.43

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2013 through 2033.

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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, 2012, NSP-Minnesota was committed to approximately $377 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 21 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.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. 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 Mechanisms — NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin operations to recover 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 143,134 MMBtu, which occurred on Jan. 19, 2012, and 134,636 MMBtu, which occurred on Jan. 20, 2011.

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 133,153 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 26 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 2012-2013 supply plan was approved by the PSCW in October 2012.

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.

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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:

2012	$	4.36
2011		5.18
2010		5.46

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 2013 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, 2012, NSP-Wisconsin was committed to approximately $86 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 12 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 Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act. PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

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

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

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

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 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. In July 2012, PSCo filed an application with the CPUC to extend the terms of the current QSP through the end of 2015. PSCo is in settlement discussions and expects to close out this matter in the first quarter of 2013.

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 1,936,810 MMBtu. In addition, firm transportation customers hold 726,530 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,663,340 MMBtu per day. The maximum daily deliveries for PSCo for firm and interruptible services were 1,539,864 MMBtu on Dec. 19, 2012 and 2,155,547 on Feb. 1, 2011.

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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 1,846,358 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 approximately 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.

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.

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:

2012	$	4.28
2011		4.99
2010		5.10

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, 2012, PSCo was committed to approximately $2.0 billion in such obligations under these contracts, which expire in various years from 2013 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 2012, 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 retail natural gas service, 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.

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Natural Gas Operating Statistics

	Year Ended Dec. 31
	2012		2011		2010
Natural gas deliveries (Thousands of MMBtu)
Residential		123,835		139,200		137,809
Commercial and industrial		77,848		86,788		87,599
Total retail		201,683		225,988		225,408
Transportation and other		116,611		117,654		121,261
Total deliveries		318,294		343,642		346,669

Number of customers at end of period
Residential		1,760,364		1,747,153		1,735,032
Commercial and industrial		154,158		153,911		152,937
Total retail		1,914,522		1,901,064		1,887,969
Transportation and other		5,789		5,395		5,281
Total customers		1,920,311		1,906,459		1,893,250

Natural gas revenues (Thousands of Dollars)
Residential	$	964,642	$	1,133,888	$	1,115,253
Commercial and industrial		488,644		601,298		589,449
Total retail		1,453,286		1,735,186		1,704,702
Transportation and other		84,088		76,740		77,880
Total natural gas revenues	$	1,537,374	$	1,811,926	$	1,782,582

MMBtu sales per retail customer		105.34		118.87		119.39
Revenue per retail customer	$	759	$	913	$	903
Residential revenue per MMBtu		7.79		8.15		8.09
Commercial and industrial revenue per MMBtu		6.28		6.93		6.73
Transportation and other revenue per MMBtu		0.72		0.65		0.64

GENERAL

Seasonality

The demand for electric power 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 for its citizens to access electric power or gas, such as municipalization. While each of Xcel Energy Inc.’s utility subsidiaries faces these challenges, Xcel Energy believes their rates are competitive with currently available alternatives.

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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 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. Currently, EPA reporting rules do not address REC transactions. It is not clear whether future GHG reporting regulations could require reporting of CO2 emissions for 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 59.1 million and 59.8 million tons of CO2 in 2012 and 2011, 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 15.1 million and 19.9 million tons of CO2 in 2012 and 2011, respectively. Estimated total CO2 emissions, associated with service to Xcel Energy electric customers, decreased by 5.5 million tons in 2012 compared to 2011. The decrease in emissions was associated with a decrease of 3.9 million MWh of generation. The average annual decrease in CO2 emissions since 2010 is approximately 2.1 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, 2012, Xcel Energy had 11,028 full-time employees and 170 part-time employees, of which 5,476 were covered under collective-bargaining agreements. See Note 9 to the consolidated financial statements for further discussion.

EXECUTIVE OFFICERS

Benjamin G.S. Fowke III, 54, 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.

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David L. Eves, 54, 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, 63, 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, 53, 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.

Kent T. Larson, 53, 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, 56, 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., 52, Senior Vice President and Chief Administrative Officer, Xcel Energy Inc., August 2012 to present. Previously, Senior Vice President and Chief Administrative Officer, Xcel Energy Services Inc., September 2011 to August 2012; 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 Services Inc., August 2009 to September 2011; Vice President, Human Resources, Xcel Energy Services Inc., July 2007 to August 2009; Vice President and Assistant Controller, Xcel Energy Services Inc., March 2005 to June 2007; and Vice President and Controller Energy Markets Business Unit, Xcel Energy Services Inc., February 2004 to February 2005.

Timothy O’Connor, 53, Senior Vice President and Chief Nuclear Officer, Xcel Energy Services Inc., February 2013 to present. Previously, Acting Chief Nuclear Officer, NSP-Minnesota, September 2012 to February 2013; Vice President, Engineering and Nuclear Regulatory Compliance and Licensing July 2012 to September 2012; Monticello Site Vice President in May 2007 to July 2012; Site Vice President and plant manager, Nine Mile Point Station, Constellation Energy, 2004 to May 2007; and corporate and site responsibilities at Public Service Enterprise Group, Hope and Salem plants, between the years of 1999 to 2004.

R. Roy Palmer, 54, 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, 52, 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, 41, 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.

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David M. Sparby, 58, 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, 52, 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, 47, 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, 56, 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

Like other companies in our industry, Xcel Energy is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition, and results of operations are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.

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. 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. Many of these risks are cross-cutting risks such that these risks 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.

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 financial 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.

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.

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Management also communicates with the Board and key stakeholders regarding risk. Management 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 including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), 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., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2012, 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, coal ash and cooling water intake systems. 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.

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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 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, in a continued low interest rate environment there could be pressure on ROE. There can also 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 or climate change regulation, 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.

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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 our 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 concerns regarding European sovereign debt and management of the U.S. federal 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 (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we expect to take advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The CFTC has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million. Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity. Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act. While we believe the impact on our liquidity will not be material, we expect to be required to report our swap transactions as part of the Dodd-Frank Act.

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.

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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 with modifications to these funding requirements in 2012 that allowed additional flexibility in the timing of contributions. 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.

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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.

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 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, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology on energy efficiency on sales and production, customer behavioral 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.

In some of our state jurisdictions, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them the authority to purchase directly from other suppliers or organized markets. The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam. Wholesale customers may purchase directly from other suppliers and procure only transmission service from our utility subsidiaries. These circumstances provide for greater long-term planning uncertainty related to future load growth. Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future, however we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation. Some state legislatures have considered such legislation.

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

Our natural gas transmission and distribution activities include a variety of inherent 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. The U.S. continues to participate in international negotiations related to 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 it is not known when the EPA will initiate this rulemaking.

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.

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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 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.

The FERC has provided NOVs of its market manipulation rules to several market participants during the year. The potential penalties in one pending case exceed $400 million. As with all regulatory requirements, we attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions. However, there is no guarantee our compliance program will be sufficient to ensure against violations.

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 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.

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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.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems, infrastructure and assets could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability. 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 incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources or of our third party service providers’ operations, could also negatively impact our business. In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level. We are unable to quantify the potential impact of such cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

Although we maintain security measures designed to protect our information technology systems, network infrastructure and other assets, these assets as well as the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. 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. We are unable to quantify the potential impact of cyber security incidents on our business.

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.

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Electric Utility Generating Stations:

NSP-Minnesota			Summer 2012
			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		327
Black Dog-Burnsville, Minn., 2 Units	Natural Gas	1987-2002		271
Blue Lake-Shakopee, Minn., 6 Units	Natural Gas	1974-2005		453
High Bridge-St. Paul, Minn., 3 Units	Natural Gas	2008		534
Inver Hills-Inver Grove Heights, Minn., 6 Units	Natural Gas	1972		282
Riverside-Minneapolis, Minn., 3 Units	Natural Gas	2009		470
Various locations, 17 Units	Natural Gas	Various		101
Wind:
Grand Meadow-Mower County, Minn., 67 Units	Wind	2008		101	(c)
Nobles-Nobles County, Minn., 134 Units	Wind	2010		201	(c)
		Total		6,982

(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 for further discussion.

(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 2012
			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		16	(a)
Combustion Turbine:
Flambeau Station-Park Falls, Wis., 1 Unit	Natural Gas	1969		12
French Island-La Crosse, Wis., 2 Units	Natural Gas	1974		122
Wheaton-Eau Claire, Wis., 6 Units	Natural Gas	1973		290
Hydro:
Various locations, 63 Units	Hydro	Various		135
		Total		631

(a)	Refuse-derived fuel is made from municipal solid waste.

Table of Contents

PSCo				Summer 2012
				Net Dependable
Station, Location and Unit	Fuel	Installed		Capability (MW)
Steam:
Arapahoe-Denver, Colo., 2 Units	Coal	1951-1955			144
Cherokee-Denver, Colo., 2 Units	Coal	1957-1968			504	(a)
Comanche-Pueblo, Colo.
Unit 1	Coal	1973			325
Unit 2	Coal	1975			335
Unit 3	Coal	2010	<