Item 1 — Business

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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 CO ₂ emissions. The statute does not impose limitations on CO ₂ 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 SO ₂ , 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:

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

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

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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.

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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.

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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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*

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 CO ₂ 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.

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.

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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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.

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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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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