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

FORM 10-K

Commission File Number: 1-3034

Xcel Energy Inc.
(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. ý Large accelerated filer o Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller Reporting Company

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

        The Registrant's Definitive Proxy Statement for its 2010 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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Index

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PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2009, Xcel Energy's continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.

Xcel Energy was incorporated under the laws of Minnesota in 1909. Xcel Energy's executive offices are located at 414 Nicollet Mall, Minneapolis, Minn. 55401. Its website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. In addition, the Xcel Energy guidelines on Corporate Governance and Code of Conduct are also available on its website.

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

NSP-Minnesota

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately 10 percent of its total sales in 2009. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 89 percent of NSP-Minnesota's retail electric operating revenues were derived from operations in Minnesota during 2009. Generally, NSP-Minnesota's earnings range from approximately 40 percent to 50 percent of Xcel Energy's consolidated net income.

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

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

NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of its total sales in 2009. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory. NSP-Wisconsin provides electric utility service to approximately 249,000 customers and natural gas utility service to approximately 105,000 customers. The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota. Approximately 98 percent of NSP-Wisconsin's retail electric operating revenues were derived from operations in Wisconsin during 2009. Generally, NSP-Wisconsin's earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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

PSCo

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 20 percent of its total sales in 2009. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers. All of PSCo's retail electric operating revenues were derived from operations in Colorado during 2009. Generally, PSCo's earnings range from approximately 45 percent to 55 percent of Xcel Energy's consolidated net income.

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

SPS

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 36 percent of its total sales in 2009. SPS provides electric utility service to approximately 396,000 retail customers in Texas and New Mexico. Approximately 74 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2009. Generally, SPS' earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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

Other Subsidiaries

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

In 1999, WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. WYCO's High Plains gas pipeline began operations in 2008 and its Totem gas storage facilities began operations in 2009. The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.

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

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

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

Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. Comparative segment revenues, income from continuing operations and related financial information are set forth in Note 20 to the accompanying consolidated financial statements.

Xcel Energy focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers. Xcel Energy files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. For more information regarding Xcel Energy's capital expenditures, see Note 17 to the consolidated financial statements.

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ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

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

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

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

Utility Restructuring and Retail Competition — The FERC has continued with its efforts to promote more competitive wholesale markets through open access transmission and other means. As a consequence, Xcel Energy's utility subsidiaries and their wholesale customers can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries' to serve their native load. In 2008, the FERC approved a MISO proposal to begin operation of a regional ASM in January 2009.

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

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

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

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SPS is also pursuing strengthening its transmission system internally to alleviate north and south congestion within the Texas Panhandle and other lines to increase the transfer capability between the Texas Panhandle and other electric systems in the SPP. Transmission expansion plans include 345 KV lines from Tuco, Texas to Woodward, Okla.

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

One state served by Xcel Energy's utility subsidiaries has implemented retail electric utility competition. In 2002, Texas implemented retail competition, but it is presently limited to utilities within the ERCOT, which does not include SPS. Under current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas. Local market conditions and political realities must be considered in proposing the transition to competition. Xcel Energy has been unable to develop a plan for the Texas Panhandle to move toward competition that would be in the best interests of its customers. As a result, Xcel Energy does not plan to propose retail competition in the Texas Panhandle. New Mexico repealed its legislation related to retail electric utility competition.

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Xcel Energy's retail electric business faces competition as industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In 2009, FERC adopted rules requiring MISO and SPP to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, NSP-Wisconsin and SPS, respectively, unless the applicable state regulatory authority prohibits ARCs from serving retail customers in its state. See further discussion in Public Utility Regulation below. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While each of Xcel Energy's utility subsidiaries faces these challenges, their rates are competitive with currently available alternatives.

NSP-Minnesota

Public Utility Regulation

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

No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generating and transmission facilities, and the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

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

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

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

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

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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.

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

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

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

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

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

NSP-Minnesota's retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred cost of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction.

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The FCAs allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or through rate cases.

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost-recovery level annually. While this law changed to a savings-based requirement beginning in 2010, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.

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

Capacity and Demand

Uninterrupted system peak demand for the NSP System's electric utility for each of the last three years and the forecast for 2010, assuming normal weather, is listed below.

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

Energy Sources and Related Transmission Initiatives

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

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

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

Purchased Transmission 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.

Excelsior Energy — In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project. The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior's petition. The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

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

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

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

The legislation also prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO₂ emissions. The statute does not impose limitations on CO₂ or other GHG emissions on NSP-Minnesota and provides for certain exemptions.

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

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

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

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Encouraging the development of solar resources; and

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Continued encouragement of DSM.

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

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

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

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Install sufficient renewables to meet the Minnesota RES;

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

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Continue ongoing capacity expansion at Sherco Unit 3;

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

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

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

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

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

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At least 15 percent of its retail sales by 2010;

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18 percent of retail sales by 2012;

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25 percent of retail sales by 2016; and

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30 percent by 2020.

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

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

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

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

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

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

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

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

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

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

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

LLW Disposal — Federal law places responsibility on each state for disposal of LLW generated within its borders. LLW from NSP-Minnesota's Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah. NSP-Minnesota is also able to utilize the Clive facility through various LLW processors. NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site LLW disposal facilities were not available.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota's spent nuclear fuel. See Item 3 — Legal Proceedings and Note 17 to the consolidated financial statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. At the following dates, casks for storage were either authorized or casks were loaded and stored:

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

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

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

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

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

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

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

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

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

Fuel Supply and Costs

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

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

Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2009 and 2008 were approximately 43 and 49 days usage, respectively. NSP-Minnesota's generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana. Estimated coal requirements at NSP-Minnesota's and NSP-Wisconsin's major coal-fired generating plants were approximately 10.2 and 11.0 million tons per year at Dec. 31, 2009 and 2008, respectively.

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

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

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

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

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

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

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

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

Natural gas — The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply, transportation and storage contracts expire in various years from 2010 to 2028. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, NSP-Minnesota's commitments related to supply contracts were $53 million and commitments related to transportation and storage contracts were approximately $538 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Wholesale Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. NSP-Minnesota uses physical and financial instruments to reduce commodity price and credit risk and hedge supplies and purchases. See additional discussion under Item 7A — Quantitative and Qualitative Disclosures about Market Risk.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of 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 and certain natural gas transactions in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see Market Based Rate Rules discussion) and is a transmission-owning member of the MISO RTO.

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

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

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

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

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

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

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

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

Wisconsin RPS and Energy Efficiency and Conservation Goals — The Wisconsin legislature has passed an RPS that requires 10 percent of electric sales statewide to be supplied by renewable energy sources by the year 2015. However, under the RPS, each individual utility must increase its renewable percentage by 6 percent over its baseline level. For NSP-Wisconsin, the RPS is 12.89 percent. NSP-Wisconsin anticipates it will meet the RPS requirements with its pro-rata share of existing and planned renewable generation on the NSP System.

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

Capacity and Demand

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

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Energy Sources and Related Initiatives

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

Fuel Supply and Costs

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

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of 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 and certain natural gas transaction in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices; however, PSCo withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

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

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

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

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

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

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

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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.

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

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

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

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

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

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

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

Capacity and Demand

Uninterrupted system peak demand for PSCo's electric utility for each of the last three years and the forecast for 2010, assuming normal weather, is listed below.

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

Energy Sources and Related Transmission Initiatives

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

Purchased Transmission 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.

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

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

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

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

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

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

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

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

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

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

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

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At least 10 percent of its retail sales for the years 2011 through 2014;

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

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20 percent of retail sales by 2020 and after; and

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

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

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

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

Fuel Supply and Costs

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

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

Fuel Sources

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

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

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

Natural gas — PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo's power plants are procured under contracts to provide an adequate supply of fuel. The supply contracts expire in various years from 2010 through 2020. The transportation and storage contracts expire in various years from 2010 to 2040. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, PSCo's commitments related to supply contracts were approximately $159 million and transportation and storage contracts were approximately $1.1 billion.

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of 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. SPS can and does then appeal municipal rate decisions to the PUCT. The NMPRC also has jurisdiction over the issuance of securities. SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce.

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

Because regulations require that actual fuel and purchased energy costs be recovered from ratepayers, there is an accounting of over- or under-recovery of fuel and purchased energy expenses under the fixed factor. Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4 percent of the utility's annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

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

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

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

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

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

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

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

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

Capacity and Demand

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

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

Energy Sources and Related Transmission Initiatives

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

Purchased Power — SPS has contracts to purchase power from other utilities and independent power producers. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased. SPS also makes short-term purchases to comply with minimum availability requirements, and to obtain energy at a lower cost.

SPS Resource Planning

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

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

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

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

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

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

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

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

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

Fuel Supply and Costs

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

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

Fuel Sources

Coal — SPS purchases all of its coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO, Inc. (TUCO). TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS' requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires in 2016. For the Tolk station, the coal supply contract with TUCO expires in 2017. As of Dec. 31, 2009, coal inventories at the Harrington and Tolk sites were approximately 46 and 54 days supply, respectively. TUCO has coal agreements to supply 89 percent of SPS' coal requirements in 2010, 37 percent of SPS' coal requirements in 2011, and 35 percent of SPS' coal requirements in 2012, which are sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

Natural gas — SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas for SPS' power plants is procured under contracts to provide an adequate supply of fuel. The supply contracts expire in 2010. The transportation and storage contracts expire in various years from 2010 to 2033. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, SPS' commitments related to supply contracts were approximately $47 million and transportation and storage contracts were approximately $253 million.

Wholesale Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy's utility subsidiaries, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy's utility activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 16 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

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

Electric Reliability Standards Compliance

Compliance Audits

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

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

NERC Compliance Investigation

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

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO. NSP-Minnesota and NSP-Wisconsin are members of the MISO RTO. SPS is a member of the SPP RTO. Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates. In 2009, PSCo filed a tariff to participate with other utilities in WestConnect, a consortium of utilities offering regionalized non-firm transmission services. The WestConnect tariff was effective in the first quarter of 2009. The WestConnect tariff has not had a material impact on PSCo transmission usage or revenues. WestConnect may provide wholesale energy market functions in the future, but would not be an RTO.

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

In January 2009, MISO began ASM operations, which provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market.

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

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

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

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

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

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

•

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

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•

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

•

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

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

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

Xcel Energy Electric Operating Statistics

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NATURAL GAS UTILITY OPERATIONS

Natural Gas Utility Trends

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

NSP-Minnesota

Public Utility Regulation

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

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

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs in the state of Minnesota. These costs are recovered from Minnesota customers through an annual cost-recovery mechanism for natural gas conservation and energy management program expenditures. This law will change to an energy savings-based requirement beginning in 2010, and the costs of conservation improvement programs will continue to be recoverable in Minnesota through a rate adjustment mechanism.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 720,983 MMBtu for 2009, which occurred on Jan. 15, 2009.

NSP-Minnesota purchases natural gas from independent suppliers. These purchases are generally priced based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 589,492 MMBtu per day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 26 percent of winter natural gas requirements and 32 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 32 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. The 2008-2009 and 2009-2010 entitlement levels are pending MPUC action.

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Natural Gas Supply and Costs

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

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

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

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2010 through 2027.

NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, NSP-Minnesota was committed to approximately $637 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 31 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.

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

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 147,362 MMBtu for 2009, which occurred on Jan. 15, 2009.

NSP-Wisconsin purchases natural gas from independent suppliers. These purchases are generally priced based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 135,633 MMBtu per day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 26 percent of winter natural gas requirements and 38 percent of peak day firm requirements of NSP-Wisconsin.

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NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin's winter 2009-2010 supply plan was approved by the PSCW in October 2009.

Natural Gas Supply and Costs

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

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

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2010 through 2029.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2009, NSP-Wisconsin was committed to approximately $126 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 13 domestic suppliers Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of 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 also subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.

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

•

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

•

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

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

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Capability and Demand

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

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

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

Natural Gas Supply and Costs

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

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

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

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

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

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Xcel Energy Natural Gas Operating Statistics

ENVIRONMENTAL MATTERS

Xcel Energy's subsidiary facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Xcel Energy facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon Xcel Energy's operations. For more information on environmental contingencies, see Notes 17 and 18 to the consolidated financial statements and Environmental Matters in Item 7 — Management's Discussion and Analysis.

CAPITAL SPENDING AND FINANCING

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

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EMPLOYEES

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

EXECUTIVE OFFICERS

Richard C. Kelly, 63, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present. Previously, President, Xcel Energy Inc., October 2003 to August 2009; Chief Operating Officer, Xcel Energy Inc., October 2003 to June 2005; Vice President and Chief Financial Officer, Xcel Energy Inc., August 2002 to October 2003 and President, Enterprises Business Unit, Xcel Energy Inc., August 2000 to August 2002.

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

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

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

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

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

Teresa S. Madden, 53, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance, Customer and Field Operations Business Unit, Xcel Energy Inc., August 2003 to January 2004; Interim CFO, Rogue Wave Software, Inc., February 2003 to July 2003 and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

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

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

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

Michael L. Swenson, 59, President, Director and Chief Executive Officer, NSP-Wisconsin, February 2002 to present. Previously, State Vice President for North Dakota and South Dakota, August 2000 to February 2002.

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

David M. Wilks, 63, Vice President, Xcel Energy Services Inc., September 2000 to present; President, Energy Supply Group, Xcel Energy Inc., August 2000 to present.

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

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Item 1A — Risk Factors

Oversight of Risk and Related Processes

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

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

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

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

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

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

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

Risks Associated with Our Business

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

We are subject to comprehensive regulation by federal and state utility regulatory agencies. The utility commissions in the states where we operate our utility subsidiaries regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

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The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the utility's costs incurred in a test year. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all the costs of our utility subsidiaries to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers. If all of the costs of our utility subsidiaries are not recovered through customer rates, they could incur financial operating losses, which, over the long term, could jeopardize their ability to pay us dividends and our ability to meet our financial obligations.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments and the payment of dividends on our common stock.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings or our subsidiaries' ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor's calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor's methodology. Therefore, Xcel Energy and its subsidiaries credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

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

We are subject to capital market risk.

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

We are subject to credit risks.

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

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

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

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

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

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

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

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

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

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

•

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

•

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

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

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

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

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

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

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

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

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

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

For further discussion, see Management's Discussion and Analysis and Note 17 to the consolidated financial statements.

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

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

•

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

•

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

•

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

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures at NSP-Minnesota's nuclear plants. In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

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

Economic conditions could negatively impact our business.

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

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

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

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC's design basis threat requirements, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

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

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

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

We are subject to information security risks.

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

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Rising energy prices could negatively impact our business.

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

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

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

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

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

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

Increased risks of regulatory penalties could negatively impact our business.

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

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

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

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

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

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

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

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

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

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

Electric Utility Generating Stations:

NSP-Minnesota

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^(a)

Based on NSP-Minnesota's ownership of 59 percent.

^(b)

This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.
Therefore, the on-demand net maximum capacity is zero.

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NSP-Wisconsin

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^(a)

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

PSCo

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^(a)

Construction of Comanche Unit 3, a 750 MW coal-fired unit, is expected to be completed in the first quarter of 2010.
PSCo will own 500 MW of the completed unit.

^(b)

Based on PSCo's ownership interest of 9.7 percent.

^(c)

Based on PSCo's ownership interest of 75.5 percent of Unit 1 and 37.4 percent of Unit 2.

^(d)

Amount represents nameplate rating capacity.

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SPS

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

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

Natural gas utility mains at Dec. 31, 2009:

Item 3 — Legal Proceedings

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

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Additional Information

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

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

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

PART II

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

Quarterly Stock Data

Xcel Energy's common stock is listed on the New York Stock Exchange (NYSE). The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2009 and 2008 and the dividends declared per share during those quarters.

Book value per share at Dec. 31, 2009, was $15.92. The number of common shareholders of record as of Dec. 31, 2009 was approximately 83,222. The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy's capitalization ratio (on a holding company basis only, not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy's holding company capitalization ratio at Dec. 31, 2009 and 2008 was 85 percent and 84 percent, respectively. Therefore, the restrictions do not place any effective limit on Xcel Energy's ability to pay dividends. For further discussion of Xcel Energy's dividend policy, see Item 7 — Management's Discussion and Analysis, Liquidity and Capital Resources.

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

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

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

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*

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

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

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Item 6 — Selected Financial Data

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^(a)

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

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

Business Segments and Organizational Overview

Continuing Operations

Xcel Energy is a public utility holding company. In 2009, Xcel Energy's continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with CIG to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.

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

Discontinued Operations

See Note 4 to the consolidated financial statements for discussion of discontinued operations.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "may," "objective," "outlook," "plan," "project," "possible," "potential," "should" and similar expressions. Actual results may vary materially.

Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations, actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy's Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2009.

Management's Strategic Plans

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

Xcel Energy's Environmental Leadership

Overview

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

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As a portfolio of regulated utilities, Xcel Energy has an obligation to serve its customers by providing them with reasonably priced, reliable electric and gas services. However, Xcel Energy's strategy goes beyond this traditional mission. Under the environmental leadership strategy, Xcel Energy takes prudent, balanced steps to reduce the impact of our operations on the environment while promoting technological and public policy advancements that will encourage a cleaner electric system. In light of the capital-intensive nature of our business, including the long life of Xcel Energy's capital investments, Xcel Energy takes prudent steps to reduce the overall risk associated with potential new environmental mandates. Finally, Xcel Energy seeks to reduce regulatory uncertainty through favorable cost-recovery for environmental initiatives provided by public policy makers, including legislatures and public utilities commissions.

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

Current Initiatives

Xcel Energy pursues environmental leadership through management of environmental policy initiatives. Xcel Energy actively evaluates public policy proposals and promotes environmental initiatives that are designed to assure compliance with state initiatives, appropriately manage long-term customer costs and, where appropriate, provide growth opportunities. These initiatives include the following:

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Xcel Energy is the nation's largest utility wind energy provider and the nation's fifth largest solar energy provider. Xcel Energy is pursuing new wind, solar and other renewable energy acquisitions and investments to meet some of the nation's most aggressive RESs in the states in which Xcel Energy operates. These standards provide for favorable cost-recovery mechanisms and investment opportunities in order to allow Xcel Energy to meet the requirements.

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Xcel Energy has implemented voluntary emission reduction programs in Minnesota and Colorado. These programs have resulted or will result in substantial emission reductions from existing facilities. They also incorporate enhanced cost-recovery mechanisms that allow for a construction work in process return and an incentive based ROE mechanism.

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

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

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

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Xcel Energy is a leader in promoting new clean energy technologies for the future. Pursuant to state statute, NSP-Minnesota manages a renewable development fund derived from customer renewable energy charges in Minnesota that allows it to promote renewable technology advancement. Xcel Energy has also initiated a study to improve wind forecasting for the industry, allowing for better integration of wind energy, and has undertaken small-scale projects to study the technical and economic aspects of energy storage and the use of hydrogen.

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Xcel Energy is a leader in supporting the advancement of solar energy technology, and has announced plans to acquire significant solar resources in Colorado, including advanced solar technology with thermal storage. Xcel Energy was a founding member of the Solar Technology Acceleration Center in Colorado, which is focused on advancing solar technology in its final stages of development.

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GHG Emissions

As one of the nation's largest electric generating companies, Xcel Energy is committed to addressing climate change through efforts to reduce its GHG emissions. Xcel Energy has adopted a methodology for calculating CO₂ emissions based on the recently issued reporting protocols of The Climate Registry. Xcel Energy is a "founding reporter" under The Climate Registry. As third-party CO₂ reporting protocols continue to evolve, Xcel Energy expects additional changes in reporting methodology and reported CO₂ emissions. Starting in 2011, Xcel Energy will also report GHG emissions to the EPA under the agency's newly adopted GHG reporting rule.

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

State Resource Plans

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

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

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

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

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

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

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Upgrade the capacity of existing nuclear facilities.

Xcel Energy has designed these plans so that, depending on fuel, commodity and other assumptions, Xcel Energy would maintain a reasonably priced product and continue to provide reliable power to our customers. At the same time, the plans would result in a significant reduction in GHG emissions. The most recently approved Minnesota plan is expected to reduce NSP-Minnesota's CO₂ emissions by 22 percent below 2005 levels by 2020. The approved Colorado plan is expected to reduce PSCo's CO₂ emissions by 10 percent to 15 percent below 2005 levels by 2015 and enables PSCo to propose additional reductions to achieve the 20 percent reduction goal by 2020, currently established by Executive Order.

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

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Achieving Financial Objectives

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

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

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

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

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

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

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

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

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

As a result of these investments, as well as continued investments in the transmission and distribution system, Xcel Energy expects that the rate base, or the amount on which Xcel Energy earns a return, will grow annually, on average, approximately 7 percent from 2009 through 2013.

The third phase is earning a fair return on utility system investments. To this end, the regulatory strategy is to receive regulatory approval for rate riders and DSM incentives, as well as general rate cases. A rate rider is a mechanism that allows recovery of certain costs and returns on investments without the costs and delays of filing a rate case. These riders allow for timely revenue recovery of the costs of large projects or other costs that vary over time. DSM incentives, which exist in Colorado and Minnesota, allow Xcel Energy to earn from helping our customers reduce energy. The incentive plans are designed to reward Xcel Energy for achieving performance at or above the approved savings goals.

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Xcel Energy's regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility investments. Xcel Energy believes that the public utility commissions will provide reasonable recovery, and it is important to note that the financial plans include this assumption. Constructive results over the last several years are evidence of reasonable regulatory treatment and give Xcel Energy confidence that Xcel Energy is pursuing the right strategy. With any strategic plan, there are goals and objectives. Xcel Energy feels the following financial objectives continue to be both realistic and achievable:

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A long-term annual earnings per share growth rate target of 5 percent to 7 percent;

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Annual dividend increases of 2 percent to 4 percent; and

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

Successful execution of the Building the Core strategic plan should allow Xcel Energy to achieve the outlined financial objectives, which in turn, should provide investors with an attractive total return on a low-risk investment. However, our operations are affected by current local, national and worldwide economic conditions. The consequences of the current recession being prolonged may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may impact the financial objectives discussed above.

Optimizing the Management of a Portfolio of Operating Utilities

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

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

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and the related notes to consolidated financial statements.

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Results of Operations

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

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

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

2009 Comparison with 2008

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

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

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

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

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

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

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

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2008 Comparison with 2007

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

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

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

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

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

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

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