Xcel Energy (XEL)

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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)

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 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 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, 2008, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $8,648,495,720 and there were 430,916,578 shares of common stock outstanding.

        As of Feb. 23, 2009, there were 454,218,905 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

        The Registrant's Definitive Proxy Statement for its 2009 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 2008, 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 a subsidiary of El Paso Corporation 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 web site address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, 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 web site.

Environmental leadership is a core strategic priority for Xcel Energy. Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value. We have established a highly effective environmental compliance program and have produced an excellent compliance record. Moreover, we pursue environmental policy initiatives that promote our environmental leadership and provide growth opportunities. Among other things, Xcel Energy is a national leader in voluntary emission reduction programs, the nation's largest retail utility wind energy provider and a leader in innovative technology, energy efficiency and conservation and customer-driven renewable energy programs. In 2007, Xcel Energy filed resource plans in Colorado and Minnesota, which are intended 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 9 percent of its total sales in 2008. 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 2008. 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 Co., which holds real estate; and NSP Nuclear Corp., which owns NMC.

NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of its total sales in 2008. 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 248,000 customers and natural gas utility service to approximately 104,000 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

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derived from operations in Wisconsin during 2008. Generally, NSP-Wisconsin's earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

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

PSCo

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 22 percent of its total sales in 2008. 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 2008. Generally, PSCo's earnings range from approximately 40 percent to 55 percent of Xcel Energy's consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; and Green and Clear Lakes Company, which owns water rights. PSCo also 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 39 percent of its total sales in 2008. SPS provides electric utility service to approximately 393,000 customers. Approximately 77 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2008. Generally, SPS' earnings range from approximately 5 percent to 10 percent of Xcel Energy's consolidated net income.

Other Subsidiaries

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

In 1999, WYCO was formed as a joint venture with a subsidiary of El Paso Corporation to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. Xcel Energy has invested approximately $128 million as of Dec. 31, 2008, for construction of WYCO's High Plains gas pipeline and the related Totem gas storage facilities. Xcel Energy plans to invest an additional $46 million in these projects in 2009 and 2010. The High Plains gas pipeline began operations in late 2008 and the Totem gas storage facilities are expected to begin operations in 2009. The gas pipeline and storage facilities will be leased under a FERC-approved agreement to Colorado Interstate Gas Company, a subsidiary of El Paso Corporation.

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

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

See financial information regarding the segments of Xcel Energy's business in Note 20 to the consolidated financial statements.

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

While Xcel Energy is not currently subject to state or federal limits on its GHG emissions, we have undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on Xcel Energy will depend on the specifics of state and federal policies, 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 Ancillary Services Market (ASM) in January 2009.

Xcel Energy supports the continued development of wholesale competition and non-discriminatory wholesale open access transmission services. 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. 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.

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

In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.

Xcel Energy's retail electric business faces competition as industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While each of Xcel Energy's utility subsidiaries faces these challenges, their rates are competitive with currently available alternatives.

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NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota's 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 and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO RTO.

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

The 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 December 2006, the MPUC authorized FCA recovery of all MISO Day 2 charges, except certain administrative charges, which NSP-Minnesota partially recovered in base rates and partially deferred for future recovery in its 2009 Minnesota electric rate case. The SDPUC and the NDPSC have authorized FCA recovery of MISO Day 2 charges. In 2008, NSP-Minnesota requested that the MPUC, NDPSC and SDPUC allow FCA treatment of all MISO ASM charges and revenues effective with the start of the ASM on Jan. 6, 2009. The SDPUC approved the request on Feb. 12, 2009. The NDPSC has concluded that the recovery was addressed and permitted through the recent rate case settlement. NSP-Minnesota will hear the matter on Feb. 26, 2009. NSP-Minnesota's electric wholesale customers also have a FCA provision in their contracts.

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

MERP Rider Regulation — In December 2003, the MPUC approved NSP-Minnesota's MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The first MERP project at the A. S. King plant went into service in July 2007. The second project at the High Bridge plant went into service in May 2008. The remaining project at the Riverside facility is expected to begin operations in 2009. The MPUC approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress. The MPUC approval has a sliding ROE scale with a range of 9.87 to 11.47 percent, based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs. At Dec. 31, 2008, the estimated ROE was 10.71 percent, based on construction progress to date.

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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 2009, assuming normal weather, is listed below.

The peak demand for the NSP System typically occurs in the summer. The 2008 system peak demand for the NSP System occurred on July 29, 2008.

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. Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy Project and Clean Energy Technology. NSP-Minnesota opposed the petition.

The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior's petition. The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

The MPUC issued its order for phase 1 of the hearing on Aug. 30, 2007. In it, the MPUC found among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the Minnesota Department of Commerce (MDOC) and the guidance provided by the order.

On Sept. 24, 2008, the MPUC denied Excelsior Energy's Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC facility. The MPUC also set a May 1, 2009 deadline for Phase 1 of the proceeding in which it had previously ordered negotiations. On Oct. 14, 2008, Excelsior sought rehearing of the MPUC's Sept. 24, 2008 order. On Dec. 9, 2008, the MPUC held further action in abeyance until after the May 1, 2009 deadline.

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. On Feb. 1, 2008, the MDOC submitted to the legislature a climate change action plan that proposes certain changes to meet the requirements of this section.

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Renewable Energy Standard (RES) — The 2007 Minnesota legislature adopted a RES statute requiring that 30 percent of NSP-Minnesota's energy requirements by 2020 come from qualifying renewable sources, primarily wind energy. Costs associated with complying with the standard are recoverable through automatic recovery mechanisms.

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

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

2008 Minnesota Legislative Session — The 2008 Minnesota legislature considered and adopted several measures related to energy policy and regulation, including:

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Encouraging Minnesota's participation in the Midwest Governors' Association's GHG accord and commissioning of an economic study of the potential impacts of a carbon cap-and-trade program;

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Modifying the existing TCR mechanism to allow for recovery of costs associated with MISO charges for regional transmission expansion;

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Providing for recovery via a rate rider mechanism of certain energy storage projects associated with renewable energy projects; and

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Providing for a streamlined approval process for wind and solar projects needed to comply with Minnesota's RES.

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

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

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Adding 2,600 MW of wind generation resources to comply with our RES of 30 percent renewable energy by 2020.

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

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

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Request approval to make environmental and capacity upgrades at Sherburne County (Sherco). The environmental upgrades would result in a significant reduction in overall SO₂, NOx and mercury emissions from the facility.

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

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

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Carbon emission reductions of 22 percent below 2005 levels by 2020.

In June 2008, intervenors filed comments on this plan. The Minnesota Office of Energy Security (OES) recommended approval, subject to further expansion of DSM goals. Environmental intervenors recommended expanded DSM goals and expressed concerns regarding carbon management with the proposed expansion of certain coal resources. Excelsior Energy recommended inclusion of its proposed project in the plan. The Prairie Island Community expressed health and safety concerns regarding nuclear resources. The Minnesota Chamber of Commerce expressed interest in cost and rate management. NSP-Minnesota filed reply comments in September 2008 providing updated information, including a

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revised forecast. As discussed below, it also withdrew its request for upgrades at Sherco Units 1 and 2. The MPUC is expected to act on the plan in the first half of 2009.

Additional Base Load Capacity Projects for Sherco, Monticello and Prairie Island — The MPUC order in the 2004 NSP-Minnesota resource plan indicated that additional capacity from the Sherco, Monticello, and Prairie Island plants would be cost-effective and should be pursued. The disclosure regarding the Monticello and Prairie Island plans is included below under "Nuclear Power Operations and Waste Disposal."

In December 2007, NSP-Minnesota filed a plan for major pollution control and efficiency improvements at Sherco Units 1 and 2 with the MPUC. The plan proposed conversion of the pollution control systems at the plant from wet scrubber precipitator technology to dry spray absorber/baghouse equipment as well as efficiency improvements that would increase the production capacity of the plant by 70 MW. The total cost of the proposed plan was estimated at $1 billion. In November 2008, NSP-Minnesota filed a request with the MPUC to withdraw the plan to reevaluate alternatives, due to significant changes in the national economy, lower forecast of energy consumption, and new information concerning an emerging technology that may be more cost effective. The MPUC granted the withdrawal request on Dec. 9, 2008.

Wind Generation — In December 2008, the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadow wind farm, went into service. The project was developed through a build-own-transfer arrangement with a large wind energy developer (enXco) at a cost of approximately $210 million. NSP-Minnesota plans to invest 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. On Dec. 3, 2008, NSP-Minnesota filed petitions with the MPUC and the NDPSC seeking the required regulatory approvals for the two wind powered generating facilities. See additional discussion of wind generation, in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations.

NSP-Minnesota Transmission Certificates of Need — In August 2007, NSP-Minnesota and Great River Energy (on behalf of eight other regional transmission providers) filed a certificate of need application, for three 345 KV 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, with construction to be completed in phases. 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. Evidentiary hearings were completed in September 2008. The OES recommended an increase in capacity for the Fargo, N. D. project. An environmental coalition supported the projects subject to conditions for wind purchases or commitments for the transmission capacity, while two other intervenors opposed the proposal. The applicants filed rebuttal testimony recommending the modification of all three projects to be constructed as double circuit compatible with the first circuit strung during initial construction and the second circuit strung as needed. NSP-Minnesota expects the ALJ to issue a report and recommendation in the first quarter of 2009. The MPUC is expected to make a final decision in 2009 after receipt of the ALJ report.

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 certificate of need application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn. A route application for this project was filed in June 2008. The need application is uncontested; route hearings are expected to be conducted in late 2009, and an MPUC decision is anticipated by the second 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 end of 2011. The estimated cost to NSP-Minnesota is approximately $26 million.

In the second quarter of 2009, NSP-Minnesota plans to file a certificate of need application with the MPUC for two 161 KV transmission lines in the Rochester, Minn. area to support ongoing development of wind powered generation in southeastern Minnesota. The proposal consists of an approximately 15 mile long, 161 KV transmission line north of Rochester, and an approximately 30 mile long, 161 KV transmission line southeast of Rochester. The project's estimated cost is $30 million. An MPUC decision is anticipated late in 2009.

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

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

Mercury Reduction and Emissions Reduction Filings — In December 2007, NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants. Currently, the estimated project costs are approximately $8.5 million. The MPUC has approved the mercury control plans. Implementation will begin in 2009. NSP-Minnesota plans to seek cost recovery of mercury control investments through an automatic rate adjustment mechanism (rate rider) filing later in 2009. As discussed above, NSP-Minnesota is reexamining its plans for emission controls at Sherco Units 1 and 2 and anticipates submitting an alternative mercury control plan with the MPUC in 2009.

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.

Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level radioactive waste (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 Barnwell facility located in South Carolina (all classes of LLW) and at the Clive facility located in Utah (class A LLW only). NSP-Minnesota had an annual contract with Barnwell that expired on June 30, 2008, but is also able to utilize the Clive facility through various LLW processors. NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site LLW disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota's spent nuclear fuel. See Item 3 — Legal Proceedings and Note 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 plants. At the following dates, casks for storage were either authorized or casks were loaded and stored:

•

In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant.

•

In 1994, the Minnesota legislature adopted a limit on dry cask storage of 17 casks.

•

In 2003, the Minnesota legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at Prairie Island, for a total of 29 casks.

•

In October 2006, the MPUC authorized an on-site storage facility and 30 casks at Monticello, which will allow the plant to operate to 2030. The MPUC decision was effective June 1, 2007.

•

As of Dec. 31, 2008, there were 24 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.

See Note 18 in the consolidated financial statements for further discussion of the matter.

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PFS — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. In February 2006, the NRC commissioners issued the license for PFS. In December 2005, the U.S. Supreme Court denied Utah's petition for a writ of certiorari to hear an appeal of a lower court's ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS. Also in December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally 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. The stated reasons were principally lack of progress at Yucca Mountain and lack of Bureau of Indian Affairs staff to monitor this activity. Both findings are expected to be appealed.

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 230 MW, to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is contingent on 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 2008 have totaled over approximately $125 million. For the years 2009 through 2015, spending is estimated at over $1.0 billion. See additional discussion in Capital Requirements in Item 7A — Management's Discussion and Analysis.

NSP-Minnesota has filed two applications for certificates of need related to its nuclear generating facilities to obtain approval for these projects. The first addresses approximately 71 MW of power uprates at the Monticello plant. The MPUC approved the Monticello power uprate certificate of need in December 2008. NSP-Minnesota re-submitted its NRC application for the Monticello plant extended power uprate in November 2008, and the NRC's Sufficiency review of the license amendment re-submittal was completed in December 2008. Although this delays the extended power uprate process slightly, NSP-Minnesota does not anticipate a substantial delay in the project at this time. The operating life of the Monticello nuclear plant has already been extended through 2030.

The second application addresses both life extension and approximately 160 MW in power uprates at Prairie Island Units 1 and 2. In July 2008, the MPUC determined that the application was complete and referred it to an ALJ for contested case hearing. The Prairie Island Community has indicated its interest in the power uprate portion of the case and has expressed interest in revisiting its 2003 settlement with NSP-Minnesota, in which it agreed that certain concerns it may have regarding Prairie Island life extension would be addressed in the federal relicensing process.

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 Prairie Island Indian Community (PIIC) filed contentions in the NRC's license renewal proceeding in August 2008. The PIIC request was referred to an Atomic Safety and Licensing Board (ASLB) for review. The ASLB has granted the PIIC hearing request and has admitted 7 of the 11 contentions filed. The resulting adjudicatory process and hearings are expected to add approximately 8 months onto the NRC's standard 22 month review schedule. Therefore the NRC is not expected to make a decision until late 2010. An application for a Certificate of Need to expand the spent fuel storage capacity at Prairie Island to support 20 additional years of operation was filed with the MPUC in May 2008. It is expected that the MPUC will act in late 2009, which would result in the MPUC decision being stayed during the 2010 session of the Minnesota legislature before going into effect.

NMC — On Sept. 28, 2007, NSP-Minnesota obtained 100 percent ownership in NMC. Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota's consolidated financial statements from the Sept. 28, 2007 transaction date. NSP-Minnesota has reintegrated its nuclear operations into its generation operations. The application to the NRC to transfer the nuclear operating licenses from NMC to NSP-Minnesota was completed on Sept. 22, 2008.

For further discussion of nuclear obligations, see Note 18 to the consolidated financial statements.

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Fuel Supply and Costs

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

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*

Includes refuse-derived fuel and wood

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

Fuel Sources

Coal — Coal inventory levels may vary widely among plants. However, the NSP System normally maintains approximately 39 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2008 and 2007, were approximately 49 and 47 days usage, based on the maximum burn rate for all of NSP-Minnesota's coal-fired plants. NSP-Minnesota's generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana. Estimated coal requirements at NSP-Minnesota's and NSP-Wisconsin's major coal-fired generating plants were approximately 11.0 and 12.4 million tons per year at Dec. 31, 2008 and 2007, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 100 percent of their coal requirements in 2009, 65 percent of their coal requirements in 2010 and 36 percent of their coal requirements in 2011. Any remaining requirements will be filled through a request for proposal (RFP) process according to the fuel supply operations procurement strategy.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2009, 100 percent of their coal requirements in 2010 and 28 percent of their coal requirements 2011. Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — To operate NSP-Minnesota's nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions.

•

Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2009, approximately 68 percent of the requirements for 2010, 80 percent of the requirements for 2011 through 2013, 47 percent of the requirements for 2014 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 2012.

•

Current contracts for conversion services cover 100 percent of the requirements through 2011 and approximately 56 percent of the requirements from 2012 through 2015, with no arrangements for 2016 and beyond.

•

Current enrichment services contracts cover 100 percent of 2009 through 2012 requirements and approximately 60 percent of 2013 requirements. A contract for additional enrichment services is being negotiated to provide the remainder of coverage for open requirements in 2013. There are currently no arrangements for 2014 and beyond. Offers for enrichment services for supply contracts for 2014 and beyond are being reviewed.

•

The fuel fabrication contract for Monticello was extended during 2007 to cover one additional reload in 2011. Request for proposals from the fuel fabrication vendors for additional supply for Monticello were distributed. Offers from fuel fabrication vendors are being reviewed with plans to enter into a contract with one of the vendors in 2009. Prairie Island's fuel fabrication is 100 percent committed to at least 2015.

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NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium are currently being negotiated that would provide additional supply requirements through 2012. 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 2009 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, 2008, NSP-Minnesota's commitments related to supply contracts were $89 million and commitments related to transportation and storage contracts were approximately $652 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 and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion).

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

Bay Front Biomass Gasification — On Feb. 23, 2009, NSP-Wisconsin filed an application for a certificate of authority to install biomass gasification technology at the Bay Front Power Plant in Ashland, Wis. Currently, two of the three boilers at Bay Front use biomass as their primary fuel to generate electricity. The proposed project will convert the existing coal-fired unit to biomass gasification technology allowing the plant to use 100 percent biomass in all three boilers. The project, estimated at $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 total generation output of the plant is not expected to change significantly as a result of the project. However, the project will improve the environmental performance of the plant and contribute towards state renewable energy standards in the region. Following all state regulatory approvals, engineering and design work is expected to begin in 2010, and the unit could be operational by late 2012. When complete, the Bay Front Power Plant will be the largest biomass-fueled power plant in the Midwest and one of the largest in the nation.

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.

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

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

Capacity and Demand

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

Energy Sources and Related Initiatives

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

Fuel Supply and Costs

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

PSCo

Public Utility Regulation

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

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

•

ECA — The ECA recovers fuel and purchase power costs. It also includes an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive can not exceed $11.25 million in any year. The ECA mechanism is revised quarterly. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

•

PCCA — The PCCA allows for recovery of purchased capacity payments for most power purchase agreements. The PCCA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.

•

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

•

AQIR — 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.

•

DSMCA — The DSMCA clause permits PSCo to recover DSM and interruptible service option credit (ISOC) costs and performance initiatives based on achieving various energy savings goals on an annual basis beginning Jan. 1, 2009.

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•

Renewable Energy Standard Adjustment (RESA) — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2.0 percent of the customer's total bill.

•

Wind Energy Service Adjustment — The Wind Energy Service Adjustment provides for the recovery of costs associated with wind energy resources from those customers subscribed to the WindSource® program.

•

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.

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

•

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

•

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

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

Capacity and Demand

Uninterrupted system peak demand for PSCo's electric utility for each of the last three years and the forecast for 2009, assuming normal weather, is listed below.

The peak demand for PSCo's system typically occurs in the summer. The 2008 system peak demand for PSCo occurred on Aug. 1, 2008.

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

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

PSCo Resource Plan — PSCo estimates it will purchase approximately 35 to 45 percent of its total electric system energy needs for 2009 under long-term contracts and generate the remainder with PSCo-owned resources. In November 2007, PSCo filed the Colorado Resource Plan (CRP), which details the type and amount of resources that will be

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added to the system for an eight year Resource Acquisition Period (RAP) through 2015. The CPUC issued its order in September 2008, which approved the following:

•

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

•

Approximately 200 MW from a central solar thermal facility with storage, with possible option of acquiring up to 600 MW of solar thermal resources with storage as technology develops;

•

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

•

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

•

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

In April 2008, the CPUC approved a certificate of public convenience and necessity application to build a new, company owned 260 MW combustion turbine project at the existing Fort St. Vrain generating station. Fort St. Vrain is scheduled to come on line in the second quarter of 2009. The Fort St. Vrain project will leave PSCo 123 MW short of the necessary peaking power and 16 percent short of reserve margin necessary to meet the 2009 summer peak load. PSCo will meet the differential for the summer 2009 peak by purchasing short-term capacity.

Construction continues on Comanche 3, a 750 MW pulverized coal-fired unit at the existing Comanche Station located near Pueblo, Colo. and installation of additional emission control equipment on the two existing Comanche Station units. Completion is planned for the fall of 2009. As part of an electric rate case, PSCo is allowed to include construction work in progress associated with the Comanche 3 project in rate base without an offset for AFDC, depending upon PSCo's senior unsecured debt rating.

PSCo has an agreement with Intermountain Rural Electric Association (IREA) and Holy Cross which transfers a portion of capacity ownership in the Comanche 3 unit to IREA and Holy Cross. IREA will take ownership of 190 MW and Holy Cross will take ownership of 60 MW upon commercial operation.

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

•

At least 10 percent of its retail sales by 2010;

•

15 percent of retail sales by 2015;

•

20 percent of retail sales by 2020; and

•

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

The new 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.

PSCo Regulatory Policy Initiative — In March 2008 open meetings, the CPUC voted to open an investigatory docket that will review the current regulatory structure to determine if current utility incentives are aligned with state public policy objectives and to determine if the existing structure is internally consistent in achieving these objectives. In June 2008, a transmission investigatory docket, was opened to gather information on transmission planning in Colorado and transmission planning coordination with other states and utilities. In September 2008, the CPUC opened a customer incentives docket whose scope covers how regulatory structure and incentives influence customer decisions.

Several parties, including PSCo filed comments in the utility incentive docket in September 2008. The comments covered a wide array of issues, including the best method to deliver DSM services to customers and the implications to utilities of owned generation or generation acquired through power purchase agreements. The comments also raised questions regarding whether or not revisions should be made to the current regulatory structure to reduce regulatory lag.

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ISOC Program — In November 2007, PSCo submitted a request to the CPUC for permission to expand its ISOC program to make it available to customers without demand history, drop the threshold for participation to 300 KW, allow customers to control load through their energy management system, increase credits and allow customers to limit the number of interruptions in a day. PSCo also sought approval for current recovery of those credits through the DSM adjustment clause. Lastly, PSCo sought authority to recover an incentive in addition to receiving reimbursement of the credits paid to customers to reward it for successful implementation of a program that reduces overall costs to its retail customers. In June 2008, the ALJ assigned to the case approved expansion of the program and removed current recovery and incentives from the current case. The CPUC upheld the ALJ's recommendation through an initial decision. Three parties filed a request for rehearing, reargument or reconsideration on limited issues. The CPUC granted the request and held deliberations on Oct. 15, 2008. In its final order, the CPUC approved expansion of the program, higher credits and concurrent recovery effective Jan. 1, 2009.

RESA — In December 2008, PSCo filed a request with the CPUC to increase the RESA to a full 2 percent in order to increase renewables to levels that comply with the 20 percent renewable energy requirement. The CPUC approved the request, and the increase became effective on Jan. 1, 2009.

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 35 days of coal inventory at each plant site. Coal supply inventories at Dec. 31, 2008 and 2007, were approximately 32 and 41 days usage, based on the maximum burn rate for all of PSCo's coal-fired plants. PSCo's generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2008 and 2007, PSCo's coal requirements for existing plants were approximately 11 million and 10 million tons, respectively.

PSCo has contracted for coal suppliers to supply 100 percent of its coal requirements in 2009, 49 percent of its coal requirements in 2010 and 34 percent of its coal requirements in 2011. Any remaining requirements will be filled through an RFP process.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2009, 93 percent of its coal requirements in 2010 and 93 percent of its coal requirements in 2011. 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 2009 and 2010. The transportation and storage contracts expire in various years from 2009 to 2040. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2008, PSCo's commitments related to supply contracts were approximately $137 million and transportation and storage contracts were approximately $1 billion.

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Wholesale Commodity Marketing Operations

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

SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS' retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have jurisdiction over SPS' rates in those communities. The NMPRC also has jurisdiction over the issuance of securities. SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.

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

The 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, 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 implement a monthly adjustment factor for a fuel and purchased power cost adjustment clause for SPS' New Mexico retail jurisdiction.

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

Performance-Based Regulation and Quality of Service Requirements — In Texas, SPS is subject to a 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. NMPRC regulations require SPS to periodically file requesting 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.

Texas Energy Efficiency Cost Recovery Factor (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 filed supplemental testimony in the currently pending Texas retail base rate case seeking cost recovery.

Texas Renewable Energy Zones — In 2007, the PUCT designated competitive renewable energy zones (CREZs), which are regions of the state that are sufficient to develop renewable energy generation sources, such as wind. Several CREZ areas within the SPS service region were designated for potential development. A statewide study conducted by the ERCOT identifies the Texas panhandle as having the top four of the state's primary areas for wind energy expansion. On Aug. 15, 2008, the PUCT issued a final order identifying a transmission plan to deliver approximately 18,000 MW of wind energy to load centers in ERCOT. The plan includes lines in the Texas Panhandle. Cost of this transmission plan is almost $5 billion, not including collector lines, and it will be paid for by ERCOT customers, not by SPS. A proceeding is now underway at the PUCT to select transmission providers to construct CREZ lines and associated facilities. Designations of transmission service providers to construct CREZ transmission projects were made at the

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PUCT open meeting on Jan. 29, 2009. In a unanimous decision, lines in Panhandle CREZs were assigned to Sharyland Utilities, Cross Texas Transmission and Wind Energy Transmission Texas (WETT). Priority lines located in central and west Texas CREZs were mostly assigned to Oncor and LCRA. These transmission providers will begin preparing certification applications.

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 holding a rulemaking to update the energy efficiency rule, consistent with the legislative changes.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2009, assuming normal weather, is listed below.

The peak demand for the SPS system typically occurs in the summer. The 2008 system peak demand for SPS occurred on Aug. 5, 2008.

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. Capacity is the measure of the rate at which a particular generating source produces electricity. Energy is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source. SPS also makes short-term purchases to comply with minimum availability requirements, and to obtain energy at a lower cost.

SPS Resource Planning

Lea Power Partners (LPP) — LPP, which was late meeting its contractual commercial operation date, was officially declared commercial on Sept. 16, 2008. Because of the delay, SPS received approximately $12 million in delay damages. The Purchase Power Agreement (PPA), which was executed in 2006, provides for SPS to have exclusive rights to the facility for a period of 25 years. LPP's generation is a two-by-one natural gas combined cycle 604 MW plant located near Hobbs, N. M.

Integrated Resource Planning — SPS is required to file an Integrated Resource Plan (IRP) before the NMPRC on or before July 2009. Also as part of this mandate, SPS must initiate a public advisory process by July 2008. Meetings have occurred periodically since the July 2008 date and are expected to continue throughout 2009 up until the time the plan is filed in July 2009.

Renewable Energy Portfolio Plan — SPS is required to file its plan with the NMPRC by July 1, 2009, for meeting the calendar year 2010 RPS. This renewable energy portfolio plan is required to include minimums of 20 percent for wind energy, 20 percent for solar energy, and 10 percent for other renewable energy technologies, as defined within the rule. The rule also requires the following minimums for distributed generation: 1 and 1.5 percent for calendar years 2011 through 2014, and 3 percent beginning in calendar year 2015. SPS released a Non-Wind RFP on Feb. 1, 2008, to meet the above regulatory mandate. SPS is contemplating execution of certain commercial agreements on or before its next filing on or before July 2009.

Pending Resource Solicitations — SPS released four RFP's during 2008. The proposals target capacity and energy resources as follows; up to 200 MW under terms of 3 to 8 years with deliveries beginning either June 2010 or June 2011, up to 200 MW of wind resources located in the Texas portion of the SPS balancing authority, and up to 600 MW of dispatchable resources with terms of up to 20 years and deliveries beginning either June 2012 or June 2013. SPS expects to have finalized each of these solicitation efforts before the end of 2009 and may seek certain regulatory approvals of any resulting agreements.

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

All of the transmission arrangements for the SPS systems are through FERC approved OATT. SPS also has several transmission arrangements through the SPP OATT. The SPP is a RTO that, among other things, administers an OATT for all its members. SPS' entire service territory is within the SPP footprint, and SPS is a member of the SPP. The SPP owns no transmission facilities. Rather, the SPP is responsible for ensuring that transmission service across facilities owned by others, including SPS, is made available and used on a reliable and non-discriminatory basis. These OATTs contain policies and procedures for reliable use of the transmission systems for transmission, generation and load variations.

Fuel Supply and Costs

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

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. With oversight from Xcel Energy, 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, 2008, coal supplies at the Harrington and Tolk sites were approximately 43 and 45 days supply, respectively. TUCO has coal agreements to supply 100 percent of SPS' coal requirements in 2009, 85 percent of SPS' coal requirements in 2010, and 40 percent of SPS' coal requirements in 2011, 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 are procured under contracts to provide an adequate supply of fuel. The supply contracts expire in 2009 and 2010. The transportation and storage contracts expire in various years from 2009 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, 2008, SPS' commitments related to supply contracts were approximately $15 million and transportation and storage contracts were approximately $271 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.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy's utility subsidiaries. State and local agencies have jurisdiction over many of Xcel Energy's utility activities,

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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 repealed PUHCA effective Feb. 8, 2006 and required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act. Since August 2005, the FERC has completed a number of rulemaking proceedings to modify its regulations on a number of subjects, including:

•

Adopting regulations requiring NERC to establish mandatory electric reliability standards; and

•

Certifying more than 120 NERC reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance. The FERC also approved certain WECC regional reliability standards as mandatory, which are applicable to PSCo.

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

Electric Reliability Standards Compliance — The 2008 developments regarding reliability standards include the following:

Compliance Audits

The NSP System and PSCo were subject to electric reliability standards compliance audits in the first and second quarters of 2008, respectively. The Midwest Reliability Organization (MRO) found the NSP System in compliance with all NERC standards audited. In September 2008, the Western Electricity Coordinating Council (WECC) auditors issued a preliminary report finding PSCo possibly non-compliant with one of the standards for which PSCo was audited. The audit report is subject to further WECC procedures.

Compliance with NERC Protective Maintenance Standards

In April 2008, the NSP System, PSCo and SPS filed self-reports with the MRO, WECC and SPP, respectively, relating to failure to complete certain generation station battery tests required by NERC protective maintenance standards. Based on preliminary discussions with the MRO, Xcel Energy expects that penalties may be assessed by certain of the NERC regional entities in conjunction with the self-reports related to incomplete generation station battery tests. The penalties are not expected to be material.

In June 2008, as a follow-up to the WECC compliance audit, PSCo filed a self-report with WECC regarding violations of its relay maintenance plan. These reviews also found a lack of complete maintenance documentation for relays on the NSP System and SPS system. The NSP System and SPS self-reported the NERC standards violations to the MRO and SPP respectively. As required by NERC procedures, PSCo, NSP, and SPS also filed mitigation plans with the regional entities to correct the testing deficiencies. The PSCo and SPS mitigation plans are complete and the NSP mitigation plan is in progress.

In September 2008, as a result of a review of its procedures implementing certain NERC critical infrastructure protection standards applicable to control centers effective July 1, 2008, PSCo, the NSP System and SPS filed self-reports disclosing certain deficiencies in requirements applicable to access to critical cyber assets to the WECC, MRO and SPP, respectively. PSCo, the NSP System and SPS filed mitigation plans within 30 days from the date of the self-reports discussing how the deficiencies were corrected.

Except as noted, Xcel Energy is uncertain if the WECC compliance audit of PSCo or the NERC standards violations self-reported in 2008 will result in financial penalties. If so, the penalties are not expected to be material.

MRO/NERC Compliance Investigation

In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the Sept. 18, 2007 event, when portions of the NSP System briefly islanded from the rest of the Eastern Interconnection, as a result of a series of transmission line outages. Because the event affected more than one region, the NERC took over the investigation. The final outcome of the NERC compliance investigation is unknown at this time. Given the ongoing investigation, Xcel Energy is unable to determine if the outcome of this matter will result in any finding of

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standards violations, and if so whether any associated penalties will have a material adverse impact on operations, cash flows or financial condition.

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. PSCo is currently participating with other utilities in the development of WestConnect, which is expected to provide certain regionalized transmission services in the first quarter of 2009 and may provide wholesale energy market functions in the future, but would not be an RTO.

In February 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules. In December 2007, the FERC issued an order on rehearing (Order No. 890-A) making certain modifications to Order No. 890, effective in March 2008. In June 2008, the FERC issued a further order on rehearing (Order No. 890-B) making certain additional modifications to Order Nos. 890 and 890-A effective in September 2008. Xcel Energy has submitted several compliance filings to modify its OATT to reflect the modified FERC rules.

Certain transmission service customers objected to aspects of the Xcel Energy Order No. 890, 890-A and 890-B compliance filings. The various compliance filings are pending final FERC action.

Under Order No. 890, transmission providers are required to post certain information on their OASIS systems. In June 2008, the FERC initiated an audit of PSCo's Order No. 890 OASIS compliance postings. PSCo was one of several electric utilities notified that the FERC was commencing such an audit. In November 2008, the FERC issued an order requiring certain compliance actions but did not impose financial penalties. PSCo concurred with the audit report, and the audit is now completed.

The FERC issued proposed rules to modify the current standards of conduct rules governing the functional separation of the Xcel Energy electric transmission function from the wholesale sales and marketing function. On Oct. 16, 2008, the FERC issued revised final rules. On Dec. 15, 2008, the FERC extended the compliance deadline for certain compliance actions to Jan. 30, 2009. Xcel Energy is taking actions to be compliant with the revised rules.

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. MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTRs. 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 will provide a more limited wholesale energy balancing market for the region that includes the SPS system.

In September 2007, MISO filed for FERC approval to establish a centralized regional wholesale ASM in 2008. The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market. In February 2008, the FERC issued an order conditionally approving the ASM tariff, but requiring certain changes. In December 2008, the FERC issued orders approving the MISO filings necessary for MISO to start the ASM. MISO began ASM operations in January 2009. To date, the ASM has generally functioned as anticipated.

In December 2007, MISO filed proposed changes to the TEMT (called Module E) to establish a long-term resource adequacy proposal. The proposal contains mandatory requirements for any market participant serving load in the MISO region, including the NSP System, to have and maintain access to sufficient resources to meet adequacy standards. The resources used to meet a resource adequacy requirement may include self-generation capacity, firm purchased power and demand response capability.

Under the Module E proposal, MISO will establish a Planning Reserve Margin for each Load-Serving Entity (LSE). The MISO resource adequacy tariff would replace the NSP System current planning reserve obligations. In March 2008, the FERC issued an order approving the Module E tariff. Various parties requested rehearing of the FERC order. MISO is expected to start Module E on March 1, 2009.

Market Based Rate Rules — In June 2007, the FERC issued a final order governing its market-based rate authorizations to electric utilities. The FERC reemphasized its commitment to market-based pricing, but is revising the tests it uses to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has

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market-based rate authorizations. Each of the Xcel Energy utility subsidiaries has been granted market-based rate authority and will be subject to the new rule. 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.

The FERC's market rate orders allow mitigated utilities such as PSCo and SPS to sell at their borders at market-based rates subject to certain conditions. Requests for rehearing addressing that aspect of the FERC's market-based rate orders are presently pending. Because PSCo makes such border sales, Xcel Energy sought such clarification from the FERC. The outcome of the rehearing request may impact the Xcel Energy utilities subsidiaries' continued ability to make such border sales at market-based rates.

Affiliate Transaction Rules — On Feb. 21, 2008, the FERC issued Order No. 707, which amended the FERC's regulations to codify restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated power sales affiliates or non-utility affiliates. The Xcel Energy utility subsidiaries are subject to the new rules. The rules apply historic SEC "at cost" pricing standards to transactions between service companies of utility holding company systems and their FERC jurisdictional public utility affiliates. In September 2008, the National Rural Electric Cooperative Association and the American Public Power Association filed a petition for review of Order No. 707 with the U.S. Court of Appeals for the District of Columbia. The appeal is pending.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, Division of Investigations (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 and responded to the DOI allegations. 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.

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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 a result of improved building construction technologies, higher appliance efficiencies, and conservation. From 1998 to 2008, average annual sales to the typical residential customer declined from 97 MMBtu per year to 83 MMBtu per year on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, the 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.

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

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 700,323 MMBtu for 2008, which occurred on Dec. 16, 2008.

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 573,668 MMBtu/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 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 33 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. The 2007-2008 and 2008-2009 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. In addition,

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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 2009 through 2028.

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, 2008, NSP-Minnesota was committed to approximately $688 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 27 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.

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 143,216 MMBtu for 2008, which occurred on Jan. 30, 2008.

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 133,546 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 26 percent of winter natural gas requirements and 39 percent of peak day, firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual

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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 2008-2009 supply plan was approved by the PSCW in October 2008.

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 2009 through 2027.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2008, NSP-Wisconsin was committed to approximately $124 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 16 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in 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.

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 monthly to allow for changes in gas rates.

•

DSMCA — PSCo has a low-income energy assistance program. The costs of this energy conservation and weatherization program 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.

Kinder Morgan Interstate Gas Transmission Bypass Pipeline — In August 2007, Kinder Morgan Interstate Gas Transmission LLC (KMIGT) filed an application with the FERC for authorizations to construct and operate 41.4 miles of 12-inch pipeline in Weld County, Colo. The stated purpose of this pipeline, referred to as the "Colorado Lateral," is to provide interstate gas transportation services of up to 55,000 dekatherms per day to supply natural gas to Atmos Energy Corporation's (Atmos) gas distribution system serving retail customers in and around Greeley and Eaton, Colo. PSCo currently provides gas transportation services to Atmos to supply its distribution system in the Greeley and Eaton

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areas. PSCo's services would be bypassed by the new KMIGT pipeline, resulting in a loss of annual revenues of approximately $3.8 million. In February 2008, the FERC issued its order approving KMIGT's application for the Colorado Lateral project.

PSCo filed a complaint at the CPUC, requesting that the CPUC enter an order finding that Atmos must cease and desist any further construction activity on the Colorado Lateral project that is under the jurisdiction of the CPUC until such time as it applies for and is granted a certificate of public convenience and necessity (CPCN). In September 2008, an ALJ issued an order that the proposed construction of the bypass laterals is not in the normal course of business and ordered Atmos to file a CPCN application for CPUC consideration and approval.

In his recommended decision, the ALJ determined that Atmos' 11-mile section of the "Colorado Lateral" would require Atmos to obtain a CPCN prior to the facilities being placed into service and that the doctrine of regulatory monopoly does not apply to the gas transportation service provided by PSCo, a local distribution company (LDC), to a downstream LDC such as Atmos. Therefore, Atmos has no expectation of service from PSCo and PSCo has no obligation to serve Atmos under the doctrine of regulated monopoly. The CPUC has confirmed the ALJ's ruling in deliberations on Feb. 5, 2009, but has not yet issued a final written order at this time.

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 1,874,731 MMBtu. In addition, firm transportation customers hold 598,660 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,473,391 MMBtu per day. The maximum daily deliveries for PSCo in 2008 for firm and interruptible services were 1,889,099 MMBtu on Dec. 15, 2008.

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 1,893,712 MMBtu/day, which includes 668,756 MMBtu of supplies held under third-party underground storage agreements. During 2008, an additional 416,419 MMBtu/Day of firm pipeline capacity was added to serve system growth. During this exercise to acquire additional firm pipeline capacity, 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 35,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo's city gate meter stations and a small amount is received directly from wellhead sources.

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 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, 2008, PSCo was committed to approximately $1.5 billion in such obligations under these contracts, which expire in various years from 2009 through 2029.

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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 2008, 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.

Xcel Energy 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. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon Xcel Energy's operations. For more information on environmental contingencies, see Notes 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 in continuing operations at Dec. 31, 2008, is presented in the table below. Of the full-time employees listed below, 5,645, or 50 percent, are covered under collective bargaining agreements. See Note 11 in the consolidated financial statements for further discussion of the bargaining agreements.

EXECUTIVE OFFICERS

Richard C. Kelly, 62, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present; President, Xcel Energy Inc., October 2003 to present. Previously, Chief Operating Officer, Xcel Energy Inc., October 2003 to June 2005, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2002 to October 2003 and President, Enterprises Business Unit, Xcel Energy Inc., August 2000 to August 2002.

Michael C. Connelly, 47, 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, 50, President and Director, SPS, December 2006 to present; Chief Executive Officer, SPS, August 2006 to present. Previously, Vice President of Resource Planning and Acquisition, Xcel Energy 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, 50, Executive Vice President, Xcel Energy Inc., December 2008 to present; Chief Financial Officer, Xcel Energy Inc., October 2003 to present; Vice President, Xcel Energy Inc., November 2002 to present. Previously, 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.

Raymond E. Gogel, 58, Vice President, Xcel Energy Services Inc., April 2002 to present; Vice President Customer and Enterprise Solutions and Chief Administrative Officer, Xcel Energy Services Inc., November 2005 to present. Previously, Chief Information Officer, Xcel Energy Services Inc., April 2002 to February 2006; Vice President and Senior Client Services Principal, IBM Global Services, April 2001 to April 2002 and Senior Project Executive, IBM Global Services, April 1999 to April 2001.

Cathy J. Hart, 59, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, Xcel Energy Inc., November 2005 to present.

Teresa S. Madden, 52, 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.

David M. Sparby, 54, President, Director and Chief Executive Officer, NSP-Minnesota, August 2008 to present; Executive Vice President and Director, Acting President and Chief Executive Officer, NSP-Minnesota, January 2007 to August 2008. Previously, Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., September 2000 to January 2007.

Michael L. Swenson, 58, President, Director and Chief Executive Officer, NSP-Wisconsin, February 2002 to present. Previously, State Vice President for North Dakota and South Dakota, August 2000 to February 2002.

Tim E. Taylor, 61, President, Director and Chief Executive Officer, PSCo, September 2007 to present. Previously, Vice President of Asset Management, Utilities Group, Xcel Energy, Inc., February 2006 to September 2007; Vice President, Field Operations, Xcel Energy Inc., January 2004 to February 2006 and Vice President, Asset Management, Xcel Energy Inc., May 2002 to January 2004.

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George E. Tyson II, 43, 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, 62, 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

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 and the sale of electric energy in interstate commerce.

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

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including 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 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, Xcel Energy is an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent Xcel Energy from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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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.

Xcel Energy may at times have direct credit exposure in its 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. Xcel Energy may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnections and MISO in which any credit losses are socialized to all market participants.

Xcel Energy does 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 Xcel Energy to exercise its contractual rights.

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

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

If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. These cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique operating conditions such as generation fuels mix, availability of fuel transportation, electric generation capacity, 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, 2008, these included:

•

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

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•

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

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

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

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

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

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

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

Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act. Xcel Energy's 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. Xcel Energy is

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advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with our environmental leadership strategy.

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

For further discussion see the Management's Discussion and Analysis section and Note 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 its licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota's nuclear plants. 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 regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the Capital Markets risk section above.

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

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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.

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.

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

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

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

The term business continuity refers to the ability of the firm to maintain day-to-day operations in response to unforeseen events, such as those in the preceding section, which describes numerous disruptions to our normal operating environment. 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-related benefits may adversely affect our results of operations, financial position, or liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006, as amended, 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 other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met.

If our utility subsidiaries were to cease making dividend payments, 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 SEC 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 interest of 59 percent.

^(b)

Installed December 2008, amount represents nameplate rating capacity.

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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)

Based on PSCo's ownership interest of 9.7 percent.

^(b)

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

^(c)

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, 2008:

Electric utility transmission and distribution substations at Dec. 31, 2008:

Natural gas utility mains at Dec. 31, 2008:

Item 3 — Legal Proceedings

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

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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, and 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 2008.

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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 2008 and 2007 and the dividends declared per share during those quarters.

Book value per share at Dec. 31, 2008, was $15.35. The number of common shareholders of record as of Dec. 31, 2008 was approximately 87,000. Xcel Energy's Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock.

At Dec. 31, 2008 and 2007, the payment of cash dividends on common stock was not restricted. For further discussion of Xcel Energy's dividend policy, see Item 7 — Management's Discussion and Analysis, Liquidity and Capital Resources.

The following compares our cumulative total shareholder return 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, 2003, and the reinvestment of all dividends).

The EEI Investor-Owned Electrics Index currently includes 59 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, 2003 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 used during construction.

^(b)

Long-term debt includes only debt of continuing operations.

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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 2008, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 8 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with a subsidiary of El Paso Corporation 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. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy's Form 10-K for the year ended Dec. 31, 2008 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2008.

Management's Strategic Plan

Xcel Energy's strategy, called Building the Core, has three primary focuses: environmental leadership, achieving financial objectives and optimizing the management of a portfolio of 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.

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

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operations on the environment while promoting technological and public policy advancements that will encourage a cleaner electric system. In light of the capital-intensive nature of our business, including the long life of Xcel Energy's capital investments, Xcel Energy takes prudent steps to reduce the overall risk associated with potential new environmental mandates. Finally, Xcel Energy seeks to reduce regulatory uncertainty through favorable cost recovery for environmental initiatives provided by public policy makers, including legislatures and public utilities commissions.

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

Current Initiatives

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

•

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

•

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

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

•

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

•

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

•

Xcel Energy is a leader in promoting new clean energy technologies for the future. Pursuant to state statute, NSP-Minnesota manages a renewable development fund derived from customer renewable energy charges in Minnesota that allows it to promote renewable technology advancement. Xcel Energy has recently proposed the creation of an innovative clean technology program in Colorado that creates a funding mechanism to explore innovative renewable and other environmentally sustainable technologies. Xcel Energy has also undertaken small-scale projects to study the technical and economic aspects of energy storage and the use of hydrogen. Xcel Energy is a leader in supporting the advancement of solar energy technology. Xcel Energy is also exploring the use of clean coal and is evaluating whether and how to best take advantage of state and federal incentives for clean coal development.

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Greenhouse Gas Emissions

While Xcel Energy is not currently subject to state or federal regulation of its GHG emissions, as one of the nation's largest electric generating companies, Xcel Energy is committed to addressing climate change through efforts to reduce its GHG emissions. This year, Xcel Energy has adopted a new 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.) Although actual historic emissions from facilities providing power to Xcel Energy customers have not changed, the new accounting methodology has resulted in an increase in Xcel Energy's reported CO₂ intensity and mass emission numbers. To enable accurate comparisons and analysis of emissions trends, Xcel Energy has recalculated historical emissions data to reflect the new accounting methodology. As third-party CO₂ reporting protocols continue to evolve, Xcel Energy expects additional changes in reporting methodology and reported CO₂ emissions.

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 66 million tons of CO₂ in 2008. 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 21 million tons of CO₂ in 2008. Estimated total CO₂ emissions, associated with service to Xcel Energy electricity customers, declined by 3.2 million tons in 2008 compared to 2007, with a combined cumulative reduction of over 21.9 million tons of CO₂ since 2003. Xcel Energy anticipates that its ownership share of Comanche 3, a new coal-fired generation project scheduled for completion in the fall of 2009, will result in CO₂ emissions of approximately 762,650 tons in 2009. Thereafter, based on Xcel Energy's emissions estimates, 3.4 million tons of CO₂ per year will be attributable to Xcel Energy's ownership share of Comanche 3. Comanche 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 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. Xcel Energy plans to implement aggressive 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

In 2007, Xcel Energy filed resource plans in Minnesota and Colorado that propose significant new clean energy resources. During 2008, the Colorado plan was approved substantially as proposed, and the Minnesota plan is still under review. Under these plans, Xcel Energy would:

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Increase overall system wind capacity from approximately 2,800 MW at the end of 2008 to approximately 7,400 MW by 2020;

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Add between 200 MW and 600 MW of concentrating solar thermal technology;

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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, if approved, the plans would result in a significant reduction in GHG emissions. The proposed Minnesota plan would reduce NSP-Minnesota's CO₂ emissions by 22 percent below 2005 levels by 2020. The proposed Colorado plan would reduce PSCo's CO₂ emissions by 10 percent below 2005 levels by 2017 and position PSCo to propose additional reductions to achieve a 20 percent reduction by 2020.

Our environmental leadership strategy has resulted in numerous environmental awards and recognition. For example, Xcel Energy was named to the Dow Jones Sustainability Index for North America for 2008-2009, which was the second consecutive year that Xcel Energy has earned this distinction. Xcel Energy strives to provide the public with detailed information regarding environmental performance and risk. Among other things, our utility companies operating in Minnesota, Colorado, and New Mexico use a carbon proxy cost mandated by the state commissions to

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evaluate the impact of potential future GHG regulation on its future resource acquisition plans. Xcel Energy publishes a Triple Bottom Line report annually, which is available on our website, www.xcelenergy.com. The Triple Bottom Line report discloses Xcel Energy's environmental, economic and social performance. Xcel Energy also provides detailed information to environmental research organizations, such as Trucost, the Carbon Disclosure Project and The Climate Registry.

Achieving Financial Objectives

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

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

•

Xcel Energy is making, 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, is currently scheduled to be placed in service by May 2009.

•

Invest approximately $1.3 billion through 2010 for Comanche 3, a project to build a new 750 MW supercritical coal unit in Colorado, scheduled to be completed in late 2009. The CPUC has approved sharing one-third ownership of this plant with other parties. Consequently, PSCo's investment in Comanche 3 will be approximately $1 billion.

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Invest approximately $192 million for the planned addition of two gas fired units totaling 300 MW at the Fort St. Vrain generating facility located in Colorado, scheduled to be completed in mid-2009.

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Invest over a $1 billion investment through 2015 to extend the lives and increase the output of our two nuclear facilities, Monticello and Prairie Island.

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Spending approximately $206 million for a new 100 MW wind farm located near Grand Meadows, Minn. The new plant was placed in service in December 2008.

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Invest 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, 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 2008 through 2012.

The third phase is earning a fair return on utility system investments. To this end, the regulatory strategy is to receive regulatory approval for rate riders as well as general rate cases. A rate rider is a mechanism that allows recovery of certain costs and returns on investments without the costs and delays of filing a rate case. These riders allow for timely revenue recovery of the costs of large projects or other costs that vary over time. Xcel Energy's regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility

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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, asset management, environmental compliance and safety.

At the same time, Xcel Energy realizes there are unique differences in each of our service territories such as local community focus and priorities, regulatory environment, physical plant infrastructure and age, weather, as well as others that require Xcel Energy to organize 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.

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy's business segments on the basis of GAAP. Continuing operations consist of the following:

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Regulated utility subsidiaries, operating in the electric and natural gas segments; and

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Other nonregulated subsidiaries and the holding company.

Discontinued operations consist of the following:

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Quixx Corp., a major portion of which was sold in October 2006;

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UE, which was sold in April 2005;

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Seren, a portion of which was sold in November 2005 with the remainder sold in January 2006;

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Cheyenne, which was sold in January 2005;

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•

NRG, which emerged from bankruptcy and was divested in late 2003; and

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

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

 

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^(a)

Not a reportable segment. Included in All Other segment results in Note 20 to the consolidated financial statements.

Earnings from continuing operations for 2008 were higher than in 2007 primarily attributed to lower operating and maintenance expense, higher electric and gas margins, and higher allowance for funds used during construction — equity. Partially offsetting these positive factors were higher depreciation and amortization, higher conservation and demand-side management program expenses, increased interest expense and a higher effective tax rate.

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

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During 2007, Xcel Energy entered into a settlement agreement with the IRS related to a dispute associated with its COLI program. The following table provides a reconciliation of GAAP earnings and earnings per share to ongoing earnings and earnings per share for the years ended Dec. 31:

 

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.

Weather — Xcel Energy's earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase operating and maintenance expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce operating and maintenance expenses. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature.

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

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Weather in 2008 did not impact earnings per share;

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Weather in 2007 increased earnings by an estimated 6 cents per share; and

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Weather in 2006 decreased earnings by an estimated 2 cents per share.

Statement of Operations Analysis — Continuing Operations

The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

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

During 2008, we experienced flat electric residential sales, primarily driven by a decline in the NSP-Minnesota region. We believe the flat sales growth is a reflection of a recent shift in customer behavior, in part, attributable to the overall economic conditions and conservation efforts. Weather-normalized sales for 2009 are projected to grow between 0.0 percent and 0.5 percent for retail electric utility customers and to decline between (1.0) percent and 0.0 percent for retail natural gas utility customers.

Electric Revenues and Margins

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

Electric — The following tables detail the electric revenues and margin:

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

Electric Revenues

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

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weather-normalized retail sales growth of approximately 1.7 percent. Unfavorable weather partially offset the positive variances.

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

Electric Margin

2008 Comparison to 2007 — The increase in electric margin for the year was due to electric rate increases at Wisconsin, North Dakota, Texas and New Mexico, higher conservation and non-fuel rider revenues and

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weather-normalized retail sales growth. These items were partially offset by unfavorable weather and higher purchased power costs.

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

Natural Gas Revenues and Margins

The following table details the changes in natural gas revenues and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin.

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

Natural Gas Revenues

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

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

Natural Gas Margin

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

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

Non-Fuel Operating Expenses and Other Items

Other Operating and Maintenance Expenses

2008 Comparison to 2007 — The decrease in operating and maintenance expenses for 2008 was largely driven by the following:

•

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

•

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

•

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

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•

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

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

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

Depreciation and amortization expense increased by $2.8 million, or 0.4 percent, for 2007, compared to 2006. Depreciation increased due to capital additions and was largely offset by the MPUC approval of NSP-Minnesota's remaining lives depreciation filing, which lengthened the life of the Monticello nuclear plant by 20 years, as well as certain other smaller plant life adjustments and adjustments to depreciable lives from the Texas rate case settlement. Both of these decisions were effective Jan. 1, 2007, and in total reduced depreciation expense by $45 million for the year.

Conservation and Demand Side Management (DSM) — Conservation and DSM expense increased $15.9 million, or 15.7 percent, for 2008, compared with 2007. The higher expense for 2008 is attributable to the expansion of programs and is designed, in part, to meet regulatory commitments. Conservation and DSM program expenses are generally recovered through riders in Xcel Energy's major jurisdictions or through general rate cases.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC increased by $30.8 million, or 42.8 percent, for 2008 when compared with 2007. The increase was due primarily to the construction of Comanche 3, which is nearing its final phase and other construction projects.

AFDC increased in total by $16.0 million for 2007 when compared to 2006. The increase was due primarily to large capital projects, including Comanche 3 and a portion of MERP, with long construction periods.

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

Interest and other income, net increased $7.0 million in 2007 compared to 2006. The increase is due primarily to higher interest income on temporary cash investments and the decrease in insurance policy interest expense related to COLI due to the settlement reached with the U.S. Government. In addition, interest and penalties related to the COLI settlement increased by $43 million in 2007, due to the settlement reached with the U.S. Government.

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

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

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

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

See Note 8 to the consolidated financial statements.

Holding Company and Other Results

The following tables summarize the net income and earnings per share contributions of the continuing operations of Xcel Energy's nonregulated businesses and holding company results: