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Xcel Energy 10-K 2008 Documents found in this filing:QuickLinks -- Click here to rapidly navigate through this document
UNITED STATES FORM 10-K
Commission File Number 1-3034 Xcel Energy Inc.
Securities registered pursuant to Section 12(g) of Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes ý No o Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Act. (Check one): ý Large accelerated filer o Accelerated filer o Non-accelerated filer o Smaller Reporting Company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý As of June 30, 2007, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $8,587,360,038 and there were 419,509,528 shares of common stock outstanding. Yes o No ý As of Feb. 14, 2008, there were 429,147,979 shares of common stock outstanding, $2.50 par value. DOCUMENTS INCORPORATED BY REFERENCE The Registrant's Definitive Proxy Statement for its 2008 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
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DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
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6 Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business. In 2007, 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 company formed to develop and lease new natural gas pipeline 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 and current reports on Form 8-K as soon as reasonably practicable after such material is 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. As discussed in detail in the Management's Discussion and Analysis section, 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 two of its operating service territories that will result in a significant reduction in CO2 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 the renewable energy mandates and take advantage of the clean energy incentives created by policy makers in the states in which we operate. NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately 10 percent of the total sales in 2007. 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 90 percent of NSP-Minnesota's retail electric operating revenues were derived from operations in Minnesota during 2007. Generally, NSP-Minnesota's earnings comprise 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 agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the NSP System, including capital costs. 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 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 the total sales in 2007. 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 246,000 customers and natural gas utility service to approximately 7 102,000 customers. The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota, as discussed previously. Approximately 98 percent of NSP-Wisconsin's retail electric operating revenues were derived from operations in Wisconsin during 2007. Generally, NSP-Wisconsin's earnings comprise 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 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 24 percent of the total sales in 2007. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility 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 2007. Generally, PSCo's earnings comprise approximately 40 percent to 50 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 owned 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 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 38 percent of the total sales in 2007. SPS provides electric utility service to approximately 388,000 customers. Approximately 76 percent of SPS' retail electric operating revenues were derived from operations in Texas during 2007. Generally, SPS' earnings comprise approximately 5 percent to 10 percent of Xcel Energy's consolidated net income. 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 jointly formed with a subsidiary of El Paso Corporation to develop and lease new natural gas pipeline and compression facilities. Xcel Energy plans to invest approximately $151 million in WYCO between 2007 and 2010. The WYCO pipeline project is expected to begin operations in 2008 and the WYCO storage project is expected to begin operations in 2009. The new pipeline and storage projects will be leased to Colorado Interstate Gas Company, a subsidiary of El Paso Corporation. The terms of the lease agreement for the new pipeline and storage projects will be based on FERC regulation and it is anticipated that they will be approved by the FERC as a component of the certificate filing to be made by the Colorado Interstate Gas Company. Xcel Energy Services Inc. is the service company for the Xcel Energy holding company system, where corporate financing activity occurs. Generally, Xcel Energy Services, Inc.'s losses comprise approximately 5 percent to 10 percent of Xcel Energy's consolidated net income. 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 at Note 18 to the consolidated financial statements. In the past, Xcel Energy had several other subsidiaries that were sold or divested. For more information regarding Xcel Energy's discontinued operations, see Note 3 to the consolidated financial statements. 8 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 for fiscal years 2007, 2006 and 2005 are set forth in Note 18 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 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 15 to the consolidated financial statements. 9
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. 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. Several of the states in which we operate 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. 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 and legislation, 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. Xcel Energy supports the continued development of wholesale competition and non-discriminatory wholesale open access transmission services. Xcel Energy will continue to work with the SPP on RTO development for the Texas Panhandle region and the incorporation of independent transmission operations to insure non-discriminatory open access. Xcel Energy is also still 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. 10
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, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 14 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. In addition, the Energy Act 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 several rulemaking proceedings to modify its regulations on a number of subjects, including:
During 2007, both state and federal legislative initiatives were introduced, with the Xcel Energy subsidiaries taking an active role in their development. 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 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 and the related responsibility 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 would provide certain regionalized transmission and wholesale energy market functions but would not be an RTO. On Feb. 15, 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules. Xcel Energy submitted the required compliance revisions to its Open Access Transmission Tariff (OATT) on July 13, 2007, Sept. 11, 2007 and Dec. 7, 2007, as required. The compliance filings are pending FERC action. On Dec. 28, 2007, the FERC issued an order on rehearing making certain modifications to Order No. 890. The revised rules will be effective in March 2008. Xcel Energy is now reviewing the amended final rules. In addition, in January 2007, the FERC issued interim and proposed rules to modify the current FERC standards of conduct rules governing the functional separation of the Xcel Energy electric transmission function from the wholesale sales and marketing function. The proposed rules are pending final FERC action. 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. Centralized Regional Wholesale Markets — The FERC rules allow RTOs to operate centralized regional wholesale energy markets. On April 1, 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 intended to provide more efficient generation 11 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 market for the region that includes the SPS system. On Sept. 14, 2007, MISO filed for FERC approval to establish a centralized regional wholesale ancillary services market (ASM) in the second quarter of 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 addition, MISO would consolidate the operation of approximately 20 existing NERC approved balancing authorities (the entity responsible for maintaining reliable operations for a defined geographic region) into a single regional balancing authority. Xcel Energy generally supports implementation of the ASM, because it is expected to allow native NSP System generation to be used more efficiently, as certain generation will not always need to be held in reserve, and to facilitate the operation of intermittent wind generation on the NSP System required to achieve state-mandated renewable energy supply standards. Comments on the ASM proposal were filed on Oct. 15, 2007, and the FERC held a technical conference on certain market power issues in November 2007. The proposal is pending FERC action. If the FERC approves the ASM tariff in February 2008 without material conditions, and if MISO can demonstrate system and operation readiness, MISO would implement the ASM on June 1, 2008. If approved by the FERC, NSP-Minnesota and NSP-Wisconsin expect to file for state regulatory approvals, as necessary, to recover ASM costs via their fuel and purchased energy cost recovery mechanisms in first quarter 2008. In another development affecting regional wholesale markets, in December 2007, MISO and some MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed proposed changes to the MISO TEMT affecting the revenue distribution of transmission revenues. Without the proposed tariff change, certain MISO transmission owners would experience an increase in prospective transmission revenues, while the revenues to other MISO transmission owners would correspondingly decrease. The proposed change did not affect 2007 results, but would essentially preserve the historic allocation of transmission service revenues in 2008 and future years. In December 2007, Ameren-Union Electric (Ameren UE) protested the proposed change. In February 2008, the FERC issued an order accepting the MISO tariff change effective February 2008 and rejecting the Ameren-UE protest. 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 market-based rate authorizations. Each of the Xcel Energy operating companies has been granted market-based rate authority and will be subject to the new rule. An aspect of the FERC's market-based rate requirements is the requirement to charge mitigated rates in markets where a utility is found to have market power. PSCo and SPS have been authorized by the FERC to charge market-based rates outside of their control areas, but are generally limited to charging mitigated rates within their control areas. PSCo and SPS use cost-based rate caps set out in the Western Systems Power Pool (WSPP) agreement as their applicable mitigated rates, an approach approved by the FERC. However, concurrently with the issuance of the final order, the FERC initiated a proceeding to investigate whether the use of the WSPP rate caps for this purpose is just and reasonable. An outcome of this proceeding may be to lower the mitigated rates that PSCo and SPS may charge in their control areas. 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 the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota and South Dakota, respectively. 12 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 that provides for monthly adjustments to billings and revenues 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 individually approved by the regulators in each jurisdiction. The FCA mechanisms 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 December 2006, the MPUC authorized FCA recovery of all MISO Day 2 charges, except certain administrative charges, which NSP-Minnesota is partially recovering in base rates and partially deferring for future recovery. In general, capacity costs are not recovered through the FCA. 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 with the remaining two projects (High Bridge and Riverside) expected to begin operations in 2008 and 2009, respectively, at a cumulative investment of approximately $1 billion. 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 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, 2007, the estimated ROE was 10.7 percent, based on construction progress to date.
Uninterrupted system peak demand for the NSP System's electric utility for each of the last three years and the forecast for 2008, assuming normal weather, are listed below.
The peak demand for the NSP System typically occurs in the summer. The 2007 system peak demand for the NSP System occurred on July 26, 2007.
NSP-Minnesota expects to use existing electric generating stations, power purchases, DSM options, new generation facilities and phased expansion of existing generation at select power plants to meet its system capacity requirements. 13 Purchased Power — NSP-Minnesota has contractual arrangements 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 replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements. Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO and regional transmission service providers to deliver power and energy to the NSP System for native load customers, which are retail and wholesale load obligations with terms of more than one year. Excelsior Energy Inc. (Excelsior) — 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 I and a second 600 MW unit in phase II 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 that:
The MPUC denied rehearing, except for certain clarifications and requiring status reports on negotiations Excelsior appealed the MPUC's decision in December 2007. The Minnesota Court of Appeals dismissed the appeal as premature because the MPUC's order on phase I is not final agency action on the entire case. Meanwhile, the ALJ issued a decision in Phase 2 of this proceeding, recommending denial of Excelsior's proposed purchase power agreement for a second IGCC project. Exceptions and replies have been filed. The MPUC is expected to take up this matter in 2008. Greenhouse Gas Emissions — The 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors producing those emissions 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 prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO2 emissions. The statute does not impose limitations on CO2 or other GHG emissions on NSP-Minnesota and provided 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. Renewable Energy Standard — The 2007 Minnesota legislature adopted a Renewable Energy Standard (RES) statute requiring NSP-Minnesota to acquire 30 percent of its energy requirements by 2020 from qualifying renewable sources, of which 25 percent must be wind energy. The legislation allows all NSP-Minnesota renewable resources to count toward meeting the standard. Costs associated with complying with the standard are recoverable through automatic recovery mechanisms. 14 NSP-Minnesota has filed with the MPUC a renewable energy plan detailing its plans 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. 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 highlights of the plan include:
The MPUC will set a schedule for consideration of the plan early in 2008. NSP-Minnesota Base Load Acquisition Proceeding — On Nov. 1, 2006, NSP-Minnesota filed a proposal with the MPUC for a purchase of 375 MW of capacity and energy from Manitoba Hydro for 2015-2025 and the purchase of 380 MW of wind energy to fulfill the base load need identified in the 2004 resource plan. An alternate supplier proposed a 375 MW share of a lignite coal generation plant to be located in North Dakota and 380 MW of wind energy generation, with an option for Xcel Energy ownership in both components. The MPUC referred the matter to a contested case proceeding. On July 20, 2007, NSP-Minnesota filed a petition asking to suspend the proceeding until NSP-Minnesota can complete its analysis of the impact of the RES and conservation goals on its need for additional resources, as outlined in the July 20, 2007 Notice of Changed Circumstance in the Resource Plan. In September 2007, the MPUC approved NSP-Minnesota's Notice of Changed Circumstance and required NSP-Minnesota to file a new resource plan by Dec. 14, 2007. NSP-Minnesota filed the 2007 resource plan, along with a proposal for closing this proceeding as the new plan does not indicate a base load resource need. The MPUC is expected to take up matter of schedule for the base load proceeding in early 2008. 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. On July 20, 2007, NSP-Minnesota filed a Notice of Changed Circumstance with the MPUC seeking to delay these proceedings until NSP-Minnesota can complete its analysis of the impact of the RES and conservation goals on its need for additional resources. In September 2007, MPUC approved the Notice of Changed Circumstance and directed NSP-Minnesota to file a new resource plan by Dec. 14, 2007. NSP-Minnesota filed the 2007 resource plan, which confirms the cost-effectiveness of these projects, and proposed to initiate filings for approval to pursue these projects in the first half of 2008. 15 NSP-Minnesota Transmission Certificates of Need — In March 2003, the MPUC granted four certificates of need to NSP-Minnesota for the construction of various transmission system upgrades for up to 825 MW of renewable energy generation (wind and biomass) in southwest and western Minnesota. The MPUC granted routing permits in 2004-05 for the major transmission facilities. NSP-Minnesota expects to complete the transmission construction in 2008 at a cost of approximately $230 million. As of Dec. 20, 2007, MISO has determined the new transmission facilities already installed provide transmission outlet capacity for up to 900 MW of renewable generation. In late 2006, NSP-Minnesota filed applications for certificates of need with the MPUC for three additional transmission lines in southwestern Minnesota and one in Chisago County, Minn. In 2007, the MPUC issued a certificate of need authorizing NSP-Minnesota to construct three new 115 KV transmission lines (totaling 35 to 50 miles) in southwestern Minnesota to provide approximately 350 MW of incremental transmission delivery capacity for wind generation. The three projects, including associated substations, are expected to cost $72.5 million. The MPUC order required NSP-Minnesota to file required route permit applications by January 2008 and complete construction by Spring 2009. The route permit applications were filed with the MPUC and SDPUC as required, and are pending MPUC and SDPUC action. In January 2008, the MPUC voted to grant NSP-Minnesota a certificate of need for the Chisago County, Minnesota project, which would replace an existing 69 KV line with 115 and 161 KV facilities and add a new substation at an estimated cost of $64 million and a route permit for the majority of the proposed line. The MPUC set the issue of the disputed route for a half-mile segment of the line for further discussions between the parties. The project would be placed in service in 2010. The PSCW has already approved construction by NSP-Wisconsin and Dairyland Power Cooperative of related 161 KV facilities in Wisconsin. As part of CapX 2020, NSP-Minnesota and Great River Energy (on behalf of nine other regional transmission providers) filed a certificate of need application in August 2007, for three 345 KV transmission lines serving Minnesota and parts of surrounding states. The current schedule targets an MPUC order by the end of 2008 or early 2009. The three lines would include construction of approximately 700 miles of new facilities at a cost of $1.4 to $1.7 billion, with construction to be completed in phases between 2011 and 2015. The application put forth a potential ownership percentage of 36 to 72 percent for each of the three 345 KV projects for NSP System. Updated NSP-Minnesota and NSP-Wisconsin cost estimates are expected following the negotiation of project agreements outlining the terms and conditions related to construction management, ownership, operations and maintenance of these facilities. 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. Pursuant to the notice, utilities in Minnesota, the MDOC and the Minnesota Office of Attorney General (MOAG) filed initial and reply comments on April 30, 2007 and June 1, 2007, respectively. 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 on going. Grand Meadow Wind Farm — In June 2007, NSP-Minnesota filed an application for a certificate of need for the Grand Meadows wind farm, a 100-MW development to be located in southeast Minnesota. The Grand Meadows project would be implemented under a build-own-transfer agreement between NSP-Minnesota and enXco, a wind project developer. Total project costs are estimated to be approximately $213 million. The MPUC approved this certificate of need and issued a site permit. Construction is expected to start in early 2008. Capital Structure Petition — In December 2007, the MPUC approved NSP-Minnesota's regular annual capital structure petition for ongoing security issuance and increased capitalization. Mercury Reduction and Emissions Reduction Filings — Pursuant to Minnesota law, in December 2007, NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercury emissions by up to 90 percent at the Sherco unit 3 and King plants. Estimated project costs amount to approximately $9.1 million. At the same time, NSP-Minnesota 16 submitted a revised filing to the MPUC for a major emissions reduction project at Sherco Units 1and 2 to reduce emissions and expand capacity. The revised filing has estimated project costs of approximately $1.1 billion. The filing also contains alternatives for the MPUC to consider additional capacity and to achieve lower emissions. If selected, these alternatives could range from $90.8 million to $330.8 million in addition to the $1.1 billion proposal. NSP-Minnesota's investments are subject to the MPUC approval of a cost recovery mechanism. Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 16 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 consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant. Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of low-level radioactive waste (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 has an annual contract with Barnwell that is scheduled to expire 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 15 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.
See Note 16 in the consolidated financial statements for further discussion of the matter. 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. The license is contingent on the condition that PFS must demonstrate that it has adequate funding before construction may begin. 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 17 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 even though the conditions had been met. 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. Prairie Island Steam Generator Replacement — Prairie Island Unit 2 steam generators received required inspections during a scheduled 2005 outage. Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 refueling outage. NSP-Minnesota Nuclear Plant Re-licensing — Monticello's renewed license expires in 2030, and Prairie Island's licenses for its two units expire in 2013 and 2014. NRC approved Monticello's renewed license in November 2006, and the MPUC order approving additional spent fuel storage to support twenty additional years of operation went into effect on June 1, 2007. Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and the MPUC, currently planned for submittal in early 2008. Nuclear Plant Power Uprates — NSP-Minnesota is seeking approval to increase the capacity of all three nuclear units that will total approximately 235 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 replacement of Unit 2's original steam generators, currently planned for replacement during the refueling outage in 2013. Capital investments for life cycle management and power uprate activities through 2007 have totaled approximately $40 million. For the years 2008 through 2015, spending is estimated at $1.1 billion. NSP-Minnesota plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs. NSP-Minnesota plans to submit the certificate of need for the Monticello uprate and the certificate of need for the Prairie Island uprate in the first quarter of 2008. NMC — On Sept. 28, 2007, Xcel Energy obtained 100 percent ownership in NMC as a result of Wisconsin Energy Corporation (WEC) exiting the partnership due to the sale of its Point Beach Nuclear Plant to FPL Energy. Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were consolidated in Xcel Energy's consolidated financial statements from the Sept. 28, 2007, transaction date. WEC was required to pay an exit fee and surrender all of its equity interest in NMC upon exiting. The effect of this transaction was not material to the financial position or the results of operations to Xcel Energy. Xcel Energy is in the process of reintegrating its nuclear operations into its generation operations and applying to the NRC to transfer the nuclear operating licenses from NMC to NSP-Minnesota. The transfer of licenses is expected to be completed in 2008. For further discussion of nuclear obligations, see Note 16 to the consolidated financial statements. The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
Fuel Sources — The NSP System normally maintains approximately 30 days of coal inventory at each plant site. Coal inventory levels, however, may vary widely among plants. Coal supply inventories at Dec. 31, 2007, were approximately 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 and NSP-Wisconsin's major coal-fired generating plants are approximately 12.4 million tons per year. NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide approximately 100 percent of its coal requirements in 2008, 63 percent of its coal requirements in 2009 and 39 percent of its coal requirements in 2010. Any remaining requirements will be filled through a request for proposal (RFP) process according to the fuel supply operations procurement strategy. 18 NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of approximately 100 percent of 2008, 2009 and 2010 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment. 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 that may be exacerbated by the supply/demand imbalance.
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 2019. Some exposure to price volatility will remain, due to index-based pricing structures on the contracts. 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 NSP System presently has no long-term supply commitments. The transportation and storage contracts expire in various years from 2010 to 2028. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2007, NSP-Minnesota's commitments related to these transportation and storage contracts were approximately $575 million. The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.
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. 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 19 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. 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 (wholesale) to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy. NSP-Wisconsin's retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period. Wisconsin Renewable Portfolio Standard — The Wisconsin legislature passed a Renewable Portfolio Standard (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 since 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. 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.
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. 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. 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, as discussed previously, 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:
20 quarterly and interest accrues monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.
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:
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. Uninterrupted system peak demand for PSCo's electric utility for each of the last three years and the forecast for 2008, assuming normal weather, are listed below.
The peak demand for PSCo's system typically occurs in the summer. The 2007 system peak demand for PSCo occurred on July 24, 2007. 21
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 contractual arrangements with regional transmission service providers to deliver power and energy to PSCo's native load customers, which are retail and wholesale load obligations with terms of more than one year. Purchased Power — PSCo has contractual arrangements 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 40 percent of its total electric system energy needs for 2008 and generate the remainder with PSCo-owned resources. Additional capacity has been secured under contract making additional energy available for purchase, if required. PSCo currently has under contract or through owned generation, the resources necessary to meet its anticipated 2008 load obligation. In November 2007, PSCo filed the Colorado Resource Plan (CRP), which details the type and amount of resources that will be added to the system for an eight year Resource Acquisition Period (RAP) through 2015. Based on the plan, PSCo would:
Also in November 2007, PSCo terminated a purchased power agreement, purchased the assets of the Squirrel Creek LLC project and filed a Certificate of Public Convenience and Necessity application with the CPUC to use the combustion turbines to build a new, company owned project at the existing Ft. St. Vrain generating station. This facility would come on line in 2009. If approved by the CPUC, the Fort St. Vrain project will leave PSCo 119 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. PSCo is requesting CPUC approval of the Fort St. Vrain application by April 2008. Construction continues on a plant approved in the last resource planning docket (2003) of a 750 MW pulverized coal-fired unit at the existing Comanche power station located near Pueblo, Colo. and installation of additional emission control equipment on the two existing Comanche station units. PSCo began construction of the new facility in the fall of 2005. 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 allowance for funds used during construction, 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. 22 Renewable Energy Standard — The 2007 Colorado legislature adopted an increased RES that requires PSCo to generate or cause to be generated electricity from renewable resources equaling:
Colorado Climate Action Plan — In November 2007, Governor Ritter of Colorado published a Colorado Climate Action Plan, which calls for a reduction in GHG emissions of 20 percent by 2020 with additional reductions by 2050. RESA — In March 2006, the CPUC approved a RESA rider of 0.6 percent. The revenues collected under the RESA will be used to acquire sufficient solar resources to meet the on-site solar system requirements in the Colorado statutes. In response to the new RES, PSCo filed in late 2007 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. TCR Legislation — In 2007, a law was passed in Colorado which provides for rate rider recovery of all costs a utility incurs in the planning, development and construction or expansion of transmission facilities and for current recovery through this rider of the utility's weighted average cost of capital on transmission construction work in progress as of the end of the prior year. This legislation also provides for rate-regulated Colorado utilities to develop plans to construct or expand transmission facilities to transmission constrained zones where new electric generation facilities, including renewable energy facilities, are likely to be located and provides for expedited approvals for such facilities. In October 2007, PSCo filed an application under the new legislation for a Certificate of Public Convenience and Necessity to construct a 345 KV transmission line from Pawnee Substation to its Smoky Hill Substation. The proposed new transmission line is intended to allow for injection of new generation capacity at Pawnee Substation for delivery to PSCo's load center located on the front range. PSCo estimates the cost of the new line to be approximately $110 million over five years. The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis under Item 7. Fuel Sources — PSCo normally maintains approximately 30 days of coal inventory at each plant site. Coal inventory levels, however, may vary widely among plants. Coal supply inventories at Dec. 31, 2007, were approximately 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 long-term contracts with suppliers operating in Colorado and Wyoming. During 2007, PSCo's coal requirements for existing plants were approximately 10 million tons. PSCo has contracted for coal suppliers to supply approximately 100 percent of its coal requirements in 2008, 76 percent of its coal requirements in 2009 and 30 percent of its coal requirements in 2010. Any remaining requirements will be filled through an RFP process according to the fuel supply operations procurement strategy. PSCo has coal transportation contracts that provide for delivery for approximately 100 percent of 2008 coal requirements, 35 percent of 2009 coal requirements and 33 percent of 2010 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment. 23 PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for associated transportation and storage services for PSCo's power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply contracts expire in various years from 2008 to 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, 2007, PSCo's commitments related to supply contracts were approximately $161 million and transportation and storage contracts were approximately $1.0 billion.
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. 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. SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices, however, as discussed previously, SPS 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 — 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 Texas retail fuel factors change each November and May based on the projected cost of natural gas. If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations 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. SPS is participating in a PUCT rulemaking project to amend the PUCT's regulations to provide for more frequent timely changes in fixed fuel factors. 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 at least every three years the operations of SPS' electric generation and fuel management activities as it relates to fuel and purchased energy costs. The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS' New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC. The NMPRC authorized SPS to implement a monthly adjustment factor. 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 quality of service plan requiring SPS to comply with electric service reliability performance targets. If these targets are not met, the PUCT staff may initiate proceedings for an investigation and possible imposition of an administrative penalty. Texas Energy Legislation — The 2005 Texas legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the ERCOT in the SPP or the WECC to have timely recovery from Texas retail consumers of utility transmission infrastructure investments. In December 2007, the PUCT adopted regulations that allow such utilities, including SPS, to seek approval of a TCR factor for recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by the FERC. 24 Texas Renewable Energy Zones — In 2007, the PUCT designated competitive renewable energy zones (CREZs), which are regions of the state which 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. Several transmission proposals have been filed in the CREZ proceeding, including plans to interconnect CREZs with the SPP and plans that would collect wind energy from panhandle CREZs and deliver it into ERCOT. Texas Goal for Renewable Energy — The Texas legislature and the PUCT have adopted renewable portfolio standards that require the development of renewable resources by 2007 and increasing requirements through 2025. SPS has already solicited for renewable energy resources and they have been developed in the SPS area and are providing renewable energy sufficient to meet the Texas renewable energy requirements. John Deere Wind Complaint — On June 27, 2007, several of the John Deere wind subsidiaries (JD Wind) filed a complaint against SPS disputing SPS' payments to JD Wind for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind for energy produced from its QF is appropriate and in accordance with SPS' filed tariffs with the PUCT. The PUCT has referred the complaint to the State Office of Administrative Hearings. New Mexico Renewable Portfolio Standard — The 2007 New Mexico legislature enacted a renewable portfolio standard in which renewable energy must comprise no less than 5 percent of retail sales by 2006; 10 percent by 2011; 15 percent by 2015; and 20 percent by 2020. The legislation also allows incentives to encourage the acquisition of renewable energy supplies beyond the requirements. The NMPRC has implemented revised rules related to the increased requirements. The NMPRC has interpreted the diversification requirement to mean no less than 20 percent of the standard is met using wind energy, no less than 20 percent using central solar, no less than 10 percent other (e.g., biomass, geothermal), and no less than 1.5 percent using renewable distributed generation (increasing to 3 percent by 2015). The effective date of the diversification requirements is 2011. Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2008, assuming normal weather, are listed below.
The peak demand for the SPS system typically occurs in the summer. The 2007 system peak demand for SPS occurred on Aug. 20, 2007.
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 contractual arrangements 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 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. SPS Resource Planning Lea Power Partners — Lea Power is a natural gas combined cycle 602 MW plant currently being constructed near Hobbs, New Mexico. SPS is expected to begin to take energy beginning June 2008 when Lea Power reaches commercial operations. The purchase power agreement, which was executed in 2006, provides for SPS to have exclusive rights to dispatch the facility. 25 Integrated Resource Planning — In accordance with a final rule adopted by the NMPRC, SPS is required to file an integrated resource plan (IRP) with the NMPRC on or before July 2009. Also as part of this requirement, SPS must initiate a public advisory process on or before July 2008. Acquisition of Renewable Resources — In accordance with a final rule adopted by the NMPRC, SPS must require certain quantities and specific types of renewable resources on or before 2011. To meet this requirement, SPS plans to submit an RFP during the first quarter of 2008. See discussion above on New Mexico Renewable Portfolio Standard. 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. The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis under Item 7. Fuel Sources — 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 the plant bunkers to meet SPS' requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers.
SPS 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 SPS' power plants are procured under contracts with various terms to provide an adequate supply of fuel. The supply contracts expire in various years from 2008 through 2010. The transportation and storage contracts expire in various years from 2008 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, 2007, SPS' commitments related to supply contracts were approximately $31 million and transportation and storage contracts were approximately $254 million. 26
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.
27
The most significant recent developments in the natural gas operations of the utility subsidiaries are continued volatility in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies. From 1997 to 2007, average annual sales to the typical residential customer declined from 102 MMBtu per year to 82 MMBtu per year on a weather-normalized basis. Although recent wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers. 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. 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 pursuant to 2007 legislation, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism. 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 643,320 MMBtu for 2007, which occurred on Feb. 7, 2007. 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 natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 562,298 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 30 percent of winter natural gas requirements and 36 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 2006-2007 and 2007-2008 entitlement levels are pending MPUC action. 28 NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths. The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota's regulated retail natural gas distribution business:
The cost of natural gas supply, transportation service and storage service is recovered through the PGA cost recovery mechanism. NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2008 through 2027. NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2007, NSP-Minnesota was committed to approximately $813 million in such obligations under these contracts. NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 25 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 Management's Discussion and Analysis under Item 7. 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. 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 173,617 MMBtu for 2007, which occurred on Feb. 4, 2007. 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 natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 129,511 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 40 percent of peak day, firm requirements of NSP-Wisconsin. 29 NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days. NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin's winter 2007-2008 supply plan was approved by the PSCW in November 2007. 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 2008 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, 2007, NSP-Wisconsin was committed to approximately $80 million in such obligations under these contracts. NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 25 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 Management's Discussion and Analysis under Item 7. 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:
Performance-Based Regulation and Quality of Service Requirements — The CPUC established a combined electric and natural gas quality of service plan. See further discussion under Item 1, Electric Utility Operations. 30 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 1,864,044 MMBtu. In addition, firm transportation customers hold 591,140 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,455,184 MMBtu per day. The maximum daily deliveries for PSCo in 2007 for firm and interruptible services were 1,798,030 MMBtu on Jan. 12, 2007. 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 natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,612,234 MMBtu/day, which includes 831,866 MMBtu of supplies held under third-party underground storage agreements. 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 period beginning July 1 through June 30 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 12-month period ending the previous June 30. 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 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, 2007, PSCo was committed to approximately $1.9 billion in such obligations under these contracts, which expire in various years from 2008 through 2028. 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 2007, PSCo purchased natural gas from approximately 40 suppliers. See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management's Discussion and Analysis under Item 7. 31
Certain of 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 15 and 16 to the consolidated financial statements, environmental matters in Management's Discussion and Analysis under Item 7 and the matters discussed below. Leyden Natural Gas Storage Facility (Leyden) — In February 2001, the CPUC approved PSCo's plan to abandon Leyden after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known. The final report of post closure monitoring will be filed with the Colorado Oil and Gas Conservation Commission in early 2008. As of Dec. 31, 2005, PSCo had incurred approximately $5.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo accrued an additional $0.2 million of costs through 2006 to complete the decommissioning and closure of the facility. In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional Leyden costs, plus unrecovered amounts authorized from a previous rate case, which amounted to $5.9 million to be amortized over four years. The total amount PSCo requested to be recovered from customers was $7.7 million. Xcel Energy reached a settlement agreement with the parties in the 2006 rate case accepting the PSCo recovery amounts. The CPUC approved the settlement agreement in June 2007. 32
For a discussion of expected capital expenditures and funding sources, see Management's Discussion and Analysis under Item 7. The number of full-time Xcel Energy employees in continuing operations at Dec. 31, 2007, is presented in the table below. Of the full-time employees listed below, 5,663, or 52 percent, are covered under collective bargaining agreements. See Note 10 in the consolidated financial statements for further discussion of the bargaining agreements.
Richard C. Kelly, 61, 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, August 2000 to August 2002. Paul J. Bonavia, 56, President — Utilities Group, Xcel Energy Inc., November 2005 to present; Vice President, Xcel Energy Services Inc., September 2000 to present. Previously, President — Commercial Enterprises Business Unit, Xcel Energy, December 2003 to October 2005 and President — Energy Markets Business Unit, Xcel Energy, August 2000 to December 2003. Michael C. Connelly, 46, Vice President and General Counsel, Xcel Energy Inc., June 2007 to present. Previously, Vice President of Human Resources November 2005 to June 2007; Vice President and Deputy General Counsel January 2003 to November 2005; Deputy General Counsel August 2000 to January 2003. David L. Eves 49, 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, November 2002 to July 2006 and Managing Director, Resource Planning and Acquisition, Xcel Energy, August 2000 to November 2002. Benjamin G.S. Fowke III, 49, Chief Financial Officer, Xcel Energy Inc., October 2003 to present; Vice President, Xcel Energy Inc., November 2002 to present. Previously, Treasurer, Xcel Energy Inc., November 2002 to May 2004 and Vice President and Chief Financial Officer — Energy Markets Business Unit, Xcel Energy, August 2000 to November 2002. Raymond E. Gogel, 57, Vice President, Xcel Energy Services Inc., April 2002 to present; Vice President Customer and Enterprise Solutions and Chief Administrative Officer, 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, 58, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, November 2005 to present. Cynthia L. Lesher, 59, President of the Minnesota host committee for the Republican National Convention as a loaned executive to the convention organization, January 2007 to present. President and Chief Executive Officer, NSP-Minnesota, October 2005 to present. Previously, Chief Administrative Officer, Xcel Energy, August 2000 to October 2005 and Chief Human Resources Officer, Xcel Energy, July 2001 to October 2005. Teresa S. Madden, 51, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance — Customer and Field Operations Business Unit, Xcel Energy, 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. 33 David M. Sparby, 53, Executive Vice President and Director, Acting President and Chief Executive Officer, NSP-Minnesota, January 2007 to present; Previously, Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., September 2000 to January 2007. Michael L. Swenson, 57, 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, 60, President, Director and Chief Executive Officer, Public Service Company of Colorado, September 2007 to present. Previously, Vice President of Asset Management — Utilities Group, Xcel Energy, Inc., February 2006 to September 2007; Vice President, Field Operations, January 2004 to February 2006 and Vice President, Asset Management, May 2002 to January 2004. George E. Tyson II, 42, Vice President and Treasurer, Xcel Energy Inc., May 2004 to present. Previously, Managing Director and Assistant Treasurer, Xcel Energy, July 2003 to May 2004; Director of Origination — Energy Markets Business Unit, Xcel Energy, May 2002 to July 2003; Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002. David M. Wilks, 61, 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. 34
Risks Associated with Our Business Our profitability depends in part on the ability of our utility subsidiaries to recover their costs from their customers and there may be changes in circumstances or in the regulatory environment that impair the ability of our utility subsidiaries to recover costs from their customers. We are subject to comprehensive regulation by federal and state utility regulatory agencies. The utility commissions in the states where our utility subsidiaries operate regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce. The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services to our customers. Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of the utility's expenses incurred in a test year. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all the costs of our utility subsidiaries to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers. If all of the costs of our utility subsidiaries are not recovered through customer rates, they could incur financial operating losses, which, over the long term, could jeopardize their ability to pay us dividends and our ability to meet our financial obligations. Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including paying dividends on our common stock. Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships. We cannot be assured that any of our current ratings or our subsidiaries' ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard and Poor's calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard and Poor's methodology. Therefore, Xcel Energy and its subsidiaries credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs. We are subject to interest rate risk. If interest rates increase, we may incur increased interest expense on variable interest debt or short-term borrowings, which could have an adverse impact on our operating results. We are subject to capital market risk. Utility operations require significant capital investment in plant, property and equipment; consequently, Xcel Energy is an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage 35 market, could prevent Xcel Energy from issuing new securities or cause us to issue securities with less than ideal terms and conditions. We are subject to credit risks. Credit risk includes the risk that counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses. We are subject to commodity risks and other risks associated with energy markets. We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. We utilize quoted observable market prices to the maximum extent possible in determining the value of these derivative commodity instruments. For positions for which observable market prices are not available, we utilize observable quoted market prices of similar assets or liabilities or indirectly observable prices based on forward price curves of similar markets. For positions for which we have unobservable market prices, we incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability. If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. These cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique operating conditions such as generation fuels mix, availability of fuel transportation, electric generation capacity, and transmission, etc. We are subject to environmental laws and regulations, compliance with which could be difficult and costly. We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2007, these included:
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations. In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations. 36 We are subject to physical and financial risks associated with climate change. There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. Xcel Energy does not serve any coastal communities so the possibility of sea level rises does not directly affect Xcel Energy or its customers. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of the company's service territory could also have an impact on Xcel Energy revenues. Xcel Energy buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts Xcel Energy service territories, primarily through thunderstorms, tornadoes and snow or ice storms. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks. To the extent climate change impacts a region's economic health, it may also impact Xcel Energy revenues. Xcel Energy's financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation, would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause Xcel Energy to receive less than ideal terms and conditions. We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly. Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. 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. Xcel Energy is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with the our environmental leadership strategy. Many of the federal and state climate change legislative proposals use a "cap and trade" policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain "allowances" or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a "cap and trade" structure, on Xcel Energy and its customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. An important factor is Xcel Energy's ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on Xcel Energy or its operating subsidiaries. If our regulators do not allow us to recover all or a part of the cost of capital 37 investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations. For further discussion see the Management's Discussion and Analysis section and Note 15 to the consolidated financial statements. Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation. NSP-Minnesota's two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota's nuclear plants. If an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota's compliance costs and impact the results of operations of its facilities. Economic conditions could negatively impact our business. Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital. Worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected. Our utility operations are subject to long term planning risks. On a periodic basis, or as needed, our utility operations file long term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production and customer response. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand. Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events. Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear 38 power plants under the NRC's design basis threat requirements, such as additional physical plant security and additional security personnel. The insurance industry has also been affected by these events and the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation, transmission systems, and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation) within our operating systems or on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results. We are subject to business continuity risks associated with our ability to respond to unforeseen events. Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results. It's difficult to predict the magnitude of such events and associated impacts. We are subject to information security risks. A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event. Rising energy prices could negatively impact our business. Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows. Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather. Our electric and natural gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations. Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs. There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater. 39 Increased risks of regulatory penalties could negatively impact our business. The Energy Act increased the FERC's civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. Effective June 2007, 83 electric reliability standards that were historically subject to voluntary compliance could negativity impact our business became mandatory and subject to potential civil penalties for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results. Increasing costs associated with our defined benefit retirement plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity. We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future. Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity. The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position, or liquidity.
We must rely on cash from our subsidiaries to make dividend payments. We are a holding company and thus our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends, depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for that purpose or for dividends on our common stock, whether by dividends or otherwise. In addition, each subsidiary's ability to pay dividends to us depends on any statutory and/or contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of equity ratios, working capital or other assets. Our utility subsidiaries are regulated by various state utility commissions, which generally possess broad powers to ensure that the needs of the utility customers are being met. If our utility subsidiaries were to cease making dividend payments, it could adversely affect our ability to pay dividends on our common stock and preferred stock or otherwise meet our financial obligations. Certain provisions of law, as well as provisions in our bylaws and shareholder rights plan, may make it more difficult for others to obtain control of us, even though some shareholders might consider this favorable. We are a Minnesota corporation and certain anti-takeover provisions of Minnesota law apply to us and create various impediments to the acquisition of control of us or to the consummation of certain business combinations with us. In addition, our shareholder rights plan contains provisions, which may make it more difficult to effect certain business combinations with us without the approval of our board of directors. Finally, certain federal and state utility regulatory statutes may also make it difficult for another party to acquire a controlling interest in us. These provisions of law and of our corporate documents, individually or in the aggregate, could discourage a future takeover attempt which individual shareholders might deem to be in their best interests or in which shareholders would receive a premium for their shares over current prices.
None. 40 Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin is subject to the lien of their first mortgage bond indentures. Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture. Electric utility generating stations:
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42 Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2007:
Electric utility transmission and distribution substations at Dec. 31, 2007:
Gas utility mains at Dec. 31, 2007:
In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. For a discussion of legal claims and environmental proceedings, see Note 15 to the consolidated financial statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates and other regulatory matters, see Pending and Recently Concluded Regulatory Proceedings under Item 1, Management's Discussion and Analysis under Item 7, and Note 14 to the consolidated financial statements under Item 8, incorporated by reference.
No issues were submitted for a vote during the fourth quarter of 2007. 43
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Xcel Energy's common stock is listed on the New York Stock Exchange (NYSE). The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2007 and 2006 and the dividends declared per share during those quarters.
Book value per share at Dec. 31, 2007, was $14.70. The number of common shareholders of record as of Dec. 31, 2007 was 91,000. Xcel Energy's Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2007 and 2006, the payment of cash dividends on common stock was not restricted. For further discussion of Xcel Energy's dividend policy, see Liquidity and Capital Resources under Item 7. The following compares our cumulative total shareholder return on common stock with the cumulative total return of the Standard & Poor's 500 Composite Stock Price Index, and the EEI Investor-Owned Electrics Index over the last five fiscal years (assuming a $100 investment in each vehicle on Dec. 31, 2002, and the reinvestment of all dividends). The EEI Investor-Owned Electrics Index currently includes 61 companies and is a broad measure of industry performance.
See Item 12 for information concerning securities authorized for issuance under equity compensation plans. 44
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Business Segments and Organizational Overview Xcel Energy is a public utility holding company. In 2007, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 8 states. These utility subsidiaries are NSP-Minnesota; NSP-Wisconsin; PSCo; and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline, these companies comprise the continuing regulated utility operations. Xcel Energy's nonregulated subsidiary reported in continuing operations is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits. See Note 3 to the consolidated financial statements for discussion of discontinued operations. Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "may," "objective," "outlook," "plan," "project," "possible," "potential," "should" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including "Risk Factors" in Item 1A of Xcel Energy's Form 10-K for the year ended Dec. 31, 2007 and Exhibit 99.01 to Xcel Energy's Form 10-K for the year ended Dec. 31, 2007. Xcel Energy's strategy, called Building the Core, has three primary focuses: environmental leadership, achieving financial objectives and optimizing the management of a portfolios of operating utilities. In summary, our objective is to embrace growing customer demand and environmental initiatives by investing in our core utility businesses and earning a reasonable return on our invested capital. Below is a detailed discussion of our three primary focuses and how they support our overall Building the Core strategy. Xcel Energy's Environmental Leadership Xcel Energy has adopted environmental leadership as a primary focus, forming the cornerstone of all our strategic initiatives. Xcel Energy believes that our environmental leadership meets customer and policy maker expectations and, in turn, creates significant shareholder value. As a portfolio of regulated utilities, Xcel Energy has an obligation to serve its customers by providing them with reasonably priced, reliable electric and gas services. However, Xcel Energy's strategy goes beyond this traditional mission. Under the environmental leadership strategy, Xcel Energy assesses and takes prudent, balanced steps to reduce the impact of our operations on the environment while promoting technological and public policy advancements that will encourage a cleaner electric system. In light of the capital-intensive nature of our business, including the long life of 46 Xcel Energy's capital investments, Xcel Energy assesses and takes prudent steps to reduce the overall risk associated with potential new environmental mandates. Finally, Xcel Energy seeks to reduce regulatory uncertainty through favorable cost recovery for environmental initiatives provided by public policy makers, including legislatures and public utilities commissions. The foundation for Xcel Energy's environmental leadership strategy resides with its environmental policy. Under this policy, the Xcel Energy Board of Directors, acting through the Nuclear, Environmental and Safety Committee, oversees Xcel Energy's environmental compliance program and policy initiatives. The policy is available on our website at www.xcelenergy.com. Xcel Energy has created an environmental management system that provides employees with training and documentation of Xcel Energy's compliance responsibilities, creates processes designed to minimize the risk of noncompliance and audits Xcel Energy's environmental performance. Environmental performance is incorporated into officer and employee job responsibilities and compensation. Xcel Energy pursues environmental leadership through management of environmental policy initiatives. Xcel Energy actively evaluates public policy proposals and promotes environmental initiatives that are designed to create shareholder value, reduce financial risk and provide growth opportunities. These initiatives include the following:
While Xcel Energy is not currently subject to state or federal regulation of its GHG emissions, as one of the nation's largest electric generating companies, Xcel Energy is committed to addressing climate change through efforts to reduce its GHG emissions. Xcel Energy's current electric generating portfolio includes coal- and gas-fired plants that are projected to emit approximately 67 million tons of CO2 in 2007. Purchased generation is expected to emit approximately 18 million tons of CO2 in 2007. There has been a combined cumulative reduction of over 18.5 million tons of CO2 since 2003. Xcel Energy is implementing aggressive future resource development and conservation plans that will further reduce the company's CO2 emissions, both in absolute terms and per Kwh of electricity produced. See Management's Discussion and Analysis for further discussion. In 2007, Xcel Energy filed resource plans in Minnesota and Colorado that propose significant new clean energy resources. If the state commissions approve these plans, Xcel Energy would:
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Xcel Energy has designed these plans so that, depending on fuel, commodity and other assumptions, Xcel Energy would maintain a reasonably priced product and continue to provide reliable power to our customers. At the same time, if approved, the plans would result in a significant reduction in CO2 emissions. The proposed Minnesota plan would reduce NSP-Minnesota's CO2 emissions by 22 percent below 2005 levels by 2020. The proposed Colorado plan would reduce PSCo's CO2 emissions by 10 percent below 2005 levels by 2017 and position PSCo to propose additional reductions to achieve a 20 percent reduction by 2020. Our environmental leadership strategy has resulted in numerous environmental awards and recognition. For example, Xcel Energy was named to the Dow Jones Sustainability Index for North America for 2007-2008, the second consecutive year that Xcel Energy has earned this distinction. Xcel Energy strives to provide the public with detailed information regarding environmental performance and risk. Among other things, our utility companies operating in Minnesota, Colorado, and New Mexico use a carbon proxy cost mandated by the state commissions to evaluate the impact of potential future CO2 regulation on its future resource acquisition plans. Xcel Energy publishes a Triple Bottom Line Report annually, which is available on our website, www.xcelenergy.com. The Triple Bottom Line report discloses Xcel Energy's environmental, economic and social performance. Xcel Energy also provides detailed information to environmental research organizations, such as Trucost, the Carbon Disclosure Project and the Climate Registry. Achieving Financial Objectives Xcel Energy's financial objectives of Building the Core also has three phases: obtaining legislative and regulatory support for large investment initiatives, investing in the utility business and earning a fair return on utility system investments. The first phase, as noted above, is obtaining legislative and regulatory support for large investment initiatives, prior to making the investment. To avoid excessive risk to Xcel Energy, it is critical that Xcel Energy reduce regulatory uncertainty before making large capital investments. Xcel Energy has accomplished this for both the MERP in Minnesota and the Comanche 3 coal unit in Colorado. Transmission legislation has been passed in Minnesota, Colorado, Texas and several other jurisdictions where Xcel Energy operates. The second phase is investing in the utility business. In addition to Xcel Energy's normal level of capital investment, Xcel Energy expects to have significant investment opportunity, in part attributable to the environmental strategy described above. Those opportunities include the following:
As a result of these investments, as well as continued investments in the transmission and distribution system, Xcel Energy expects that the rate base, or the amount on which Xcel Energy earns a return, will grow on average annually by more than seven percent from 2006 through 2011. 48 The third phase is earning a fair return on utility system investments. To this end, the regulatory strategy is to receive regulatory approval for rate riders as well as general rate cases. A rate rider is a mechanism that allows recovery of certain costs and returns on investments without the costs and delays of filing a rate case. These riders allow for timely revenue recovery of the costs of large projects or other costs that vary over time. As an example, a rider for MERP went into effect in January 2006, allowing Xcel Energy to earn a return on the project, while each of the facilities is being constructed. Xcel Energy's regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on utility investments. Xcel Energy believes that the public utility commissions will provide reasonable recovery, and it is important to note that the financial plans include this assumption. Constructive results over the last several years are evidence of reasonable regulatory treatment and give Xcel Energy confidence that Xcel Energy is pursuing the right strategy. These rate cases, as well others planned for 2008 and beyond, are some of the building blocks of the earnings growth plan. With any strategic plan, there are goals and objectives. Xcel Energy feels the following financial objectives continue to be both realistic and achievable.
Successful execution of the Building the Core strategic plan should allow Xcel Energy to achieve the outlined financial objectives, which in turn should provide investors with an attractive total return on a low-risk investment. Optimizing the Management of a Portfolio of Operating Utilities Optimizing the management of a portfolio of operating utilities is the third area of focus related to the Building the Core strategy. Even though Xcel Energy ultimately manages the business based on the revenue streams provided by electric and natural gas, Xcel Energy continues to evolve the management of the portfolio of utility investments. While Xcel Energy has four separate operating companies, there are certain similarities and differences that require a new approach to more effectively manage this portfolio. More specifically, Xcel Energy's goal is to build on the similarities among the companies, which maximizes efficiencies from centralized management and deployment of common initiatives. Examples include market branding and environmental policy research. From an organizational perspective, examples include corporate center services as well as certain operational functions, such as asset management, environmental compliance and safety. At the same time, Xcel Energy realizes there are unique differences in each of our service territories such as local community focus and priorities, regulatory environment, physical plant infrastructure and age, weather, as well as others that require Xcel Energy to organize / align these utility specific areas to most effectively address these utility distinct characteristics. To that end, Xcel Energy has operating presidents, each located in their respective jurisdiction. The objective of this organizational structure is to optimize Xcel Energy's operating efficiency while maximizing accountability. The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying consolidated financial statements and the related notes to consolidated financial statements. All note references refer to the notes to consolidated financial statements. The following table summarizes the earnings contributions of Xcel Energy's business segments on the basis of GAAP. Continuing operations consist of the following:
49 Discontinued operations consist of the following:
See Note 3 to the consolidated financial statements for a further discussion of discontinued operations.
Earnings from continuing operations for 2007 were higher than in 2006. The increase in 2007 earnings were primarily attributed to higher electric and gas margins, reflecting various rate increases, weather-normalized retail sales growth, higher rider recovery, and the impact of favorable temperatures, which also increased sales. Partially offsetting these positive factors were higher operating and maintenance expense, increased interest expense and a higher effective tax rate. Earnings from continuing operations for 2006 were higher than in 2005. The increase in 2006 earnings was primarily due to stronger base electric utility margin. The higher margin reflects electric rate increases in various jurisdictions, weather-adjusted retail electric sales growth and revenue associated with investments in MERP. In addition, earnings increased due to the recognition of income tax benefits. Partially offsetting these positive factors were expected increases in expenses for operations, maintenance and depreciation and lower short-term wholesale margins. 50 During 2007, Xcel Energy entered into a settlement agreement with the IRS related to a dispute associated with its COLI program. Excluding this settlement, along with the earnings associated with this insurance program, Xcel Energy's ongoing 2007 earnings were $612 million, or $1.43 per share, compared with 2006 ongoing earnings of $548 million or $1.30 per share. The following table provides a reconciliation of GAAP earnings and earnings per share to ongoing earnings and earnings per share for 2007, 2006 and 2005.
As a result of the termination of the COLI program, Xcel Energy's management believes that ongoing earnings provide a more meaningful comparison of earnings results between different periods in which the COLI program was in place and is more representative of Xcel Energy's fundamental core earnings power. Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for performance-based compensation and when communicating its earnings outlook to analysts and investors. Income from discontinued operations in 2005 includes the positive impact of a $17 million tax benefit recorded to reflect the final resolution of Xcel Energy's divested interest in NRG. This was partially offset by Seren's operating losses during 2005.
Weather — Xcel Energy's earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per degree of temperature. The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:
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The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers in most states, the fluctuations in these costs do not materially affect electric utility margin. Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy-related purchase and sales activity, and the use of financial instruments associated with the fuel required for, and energy produced from, Xcel Energy's generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with Xcel Energy's generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable. Commodity trading revenues are reported net of related costs (i.e., on a margin basis) in the consolidated statements of income. Commodity trading costs include purchased power, transmission, broker fees and other related costs. The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:
52 The following summarizes the components of the changes in base electric utility revenues and base electric utility margin for the years ended Dec. 31: Base Electric Utility Revenues
2007 Comparison with 2006 — Base electric utility revenues increased due to a PSCo electric retail rate increase, weather-normalized retail sales growth of approximately 1.7 percent, higher transmission revenues, higher recovery from the MERP rider, which recovers financing and other costs related the MERP construction projects and higher conservation and non-fuel rider recovery, mostly from the RESA and DSM riders at PSCo. Lower fuel and purchased power costs, largely recovered from customers, partially offset the positive variances.
2006 Comparison with 2005 — Base electric utility revenues increased due to rate increases in Minnesota and Wisconsin, higher fuel and purchased power costs, largely recoverable from customers, weather-normalized retail sales growth of approximately 1.8 percent, and the implementation of the MERP rider to recover financing and other costs related the MERP construction projects. Base Electric Utility Margin
53 2007 Comparison to 2006 — The increase in base electric margin for the year was due to PSCo electric rate increase, the impact of favorable temperatures and weather normalized retail sales growth. These items were partially offset by purchased power costs, NSP-Wisconsin fuel cost recovery and other items.
2006 Comparison to 2005 — Base electric utility margins, which are primarily derived from retail customer sales, increased due to rate increases in Minnesota and Wisconsin, weather-normalized retail sales growth, the implementation of the MERP rider, and higher firm wholesale margins. Partially offsetting the increase, is a transmission fee classification change from other operating and maintenance expenses-utility in 2005 to electric utility margin in 2006, which did not impact operating income or net income. The change resulted from an analysis conducted in conjunction with the expiration and renegotiation of certain transmission agreements, resulting in better alignment of reporting such costs consistent with MISO classification. In addition, the ECA incentive earned in Colorado in 2006 resulted in a loss, as compared to a gain in 2005. Short-Term Wholesale and Commodity Trading Margin 2007 Comparison to 2006 — Short-term wholesale and commodity trading margins decreased approximately $13 million for 2007 compared to 2006. As expected, short-term wholesale margins declined due to retail sales growth, which reduced generation available for sale in the wholesale market. 2006 Comparison to 2005 — As expected, short-term wholesale and commodity trading margins declined by $43 million for 2006 compared with 2005, due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, reductions in the availability of the coal-fired King plant due to the MERP project, decreased opportunities to sell due to the MISO centralized dispatch market and the Minnesota rate case settlement agreement to refund to customers the majority of short-term wholesale margins attributable to Minnesota jurisdiction customers starting in 2006.
The following table details the changes in natural gas utility revenues and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin. See further discussion under Factors Affecting Results of Continuing Operations.
54 The following summarizes the components of the changes in natural gas revenues and margin for the years ended Dec. 31: Natural Gas Revenues
2007 Comparison to 2006 — Natural gas revenues decreased primarily due to lower natural gas costs in 2007, which are recovered from customers. Interim rate increases were effective for Minnesota in January 2007 and base rates increased for Colorado and North Dakota customers in July 2007. 2006 Comparison to 2005 — Natural gas revenues decreased primarily due to lower natural gas costs in 2006, which are recovered from customers. Retail natural gas weather-normalized sales declined when compared to 2005, largely due to declining use per customer. Natural Gas Margin
2007 Comparison to 2006 — Natural gas margins increased due to interim rate increases, which were effective for Minnesota in January 2007, and base rate increases for Colorado and North Dakota customers in July 2007. 2006 Comparison to 2005 — Natural gas margins increased in 2006 due to rate increases in Colorado, Wisconsin and Minnesota. Base rate changes include a full year of new rates for Minnesota in 2006 as compared to two months of increase in 2005.
Other Operating and Maintenance Expenses
55 2007 Comparison to 2006 — The increase in operating and maintenance expenses for 2007 was largely driven by recording a $17 million regulatory asset for private nuclear fuel storage costs which had been previously expensed and higher net gains on sales of assets in 2006. Also, higher combustion/hydro and nuclear plant costs increased operating and maintenance expense. Offsetting these increases in operating and maintenance expenses were lower performance based incentive plan expense as well as lower healthcare expense. Also partially offsetting the increased operating and maintenance expenses were lower nuclear plant outage costs, due to two refueling outages in 2006 versus only one outage in 2007.
2006 Comparison to 2005 — Other operating and maintenance expenses for 2006 increased $66 million, or 3.9 percent, compared with 2005. Higher employee benefit costs, which are primarily performance-based, higher nuclear and combustion/hydro plant costs were offset by lower nuclear plant outage costs, the transmission reclassification, gains on sales of assets, and the establishment of the private fuel storage regulatory asset, based on a regulatory decision. Depreciation and Amortization — Depreciation and amortization expense increased by approximately $5 million, or 0.6 percent, for 2007, compared to 2006. Depreciation increased due to capital additions and was largely offset by the MPUC approval of NSP-Minnesota's remaining lives depreciation filing, which lengthened the life of the Monticello nuclear plant by 20 years, as well as certain other smaller plant life adjustments and adjustments to depreciable lives from the Texas rate case settlement. Both of these decisions were effective Jan. 1, 2007, and in total reduced depreciation expense by $45 million for the year. Depreciation and amortization expense increased by approximately $55 million, or 7.1 percent, for 2006 compared with 2005. Decommissioning accruals increased $20 million in 2006. Normal plant additions accounted for the remaining increase in depreciation expense for 2006 over 2005. AFDC — AFDC increased in total by $16 million for 2007 when compared to 2006. The increase was due primarily to large capital projects, including Comanche 3 and a portion of MERP, with long construction periods. AFDC increased in total by approximately $14 million for 2006 when compared to 2005. The increase was due primarily to large capital projects beginning in 2005 and 2006, including MERP and Comanche 3, with long construction periods. The increase was partially offset by the current recovery from customers of the financing costs related to MERP through a MERP rider resulting in a lower recognition of AFDC. Interest and Other Income (Expense), Net — Interest and other income (expense), net increased $7 million in 2007 compared to 2006. The increase is due primarily to higher interest income on temporary cash investments and the decrease in insurance policy interest expense related to COLI due to the settlement reached with the U.S. Government. In addition, interest and penalties related to the COLI settlement, increased by $43 million in 2007, due to the settlement reached with the U.S. Government. Interest and other income (expense) net increased $3 million in 2006 compared to 2005. The increase is due primarily to higher interest income on temporary cash investments, and the deferred fuel assets in Texas. Interest and Financing Costs — Interest charges increased by approximately $33 million, or 6.8 percent, for 2007 compared with 2006. The increase is due to higher levels of both short-term and long-term debt and higher interest rates. 56 Interest charges increased by approximately $24 million, or 5.1 percent, for 2006 compared with 2005. The increase is due to higher levels of both short-term and long-term debt and higher short-term interest rates. Income Tax Expense — Income taxes for continuing operations increased by $113 million for 2007, compared with 2006. The increase in income tax expense was primarily due to an increase in pretax income (excluding COLI) and $16.1 million of tax expense related to the COLI settlement in 2007 and $29.9 million of tax benefits from the reversal of a regulatory reserve and realized capital loss carry forwards in 2006. The effective tax rate for 2007 was 33.8 percent, compared with 24.2 percent for the same period in 2006. The higher effective tax rate for 2007 was primarily due to the COLI settlement and the lower effective tax rate for 2006 was primarily due to the recognition of a tax benefit relating to the reversal of a regulatory reserve and realized capital loss carry forwards. Without these charges and benefits, the effective tax rate for 2007 and 2006 would have been 30.3 percent and 28.2 percent, respectively. Income taxes for continuing operations increased by $8 million for 2006, compared with 2005. The effective tax rate for continuing operations was 24.2 percent for 2006, compared with 25.8 percent for 2005. The increase in income tax expense was primarily due to an increase in pretax income, partially offset by $30 million of tax benefits from the reversal of a regulatory reserve and realized capital loss carry forwards. Without these tax benefits the effective tax rate for 2006 would have been 28.2 percent. See Note 7 to the consolidated financial statements.
The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy's nonregulated businesses and holding company results:
Financing Costs and Preferred Dividends — Holding company and other results include interest expense and the earnings-per-share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries. The earnings-per-share impact of financing costs and preferred dividends for 2007, 2006 and 2005 included above reflects dilutive securities, as discussed further in Note 8 to the consolidated financial statements. The impact of the dilutive securities, if converted, is a reduction of interest expense resulting in an increase in net income of approximately $10 million in 2007; $15 million in 2006; and $14 million in 2005. 57
A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:
In January 2004, Xcel Energy agreed to sell Cheyenne. Consequently, Xcel Energy reported Cheyenne results as a component of discontinued operations for all periods presented. The sale was completed in January 2005 and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued in December 2004. In 2006, the Cheyenne basis study was updated resulting in the recognition of $2.3 million in tax benefits. This plus other Cheyenne related tax benefits totaled $3.3 million or 1 cent per share.
In April 2005, Zachry Group, Inc. (Zachry) acquired all of the outstanding shares of UE, a nonregulated subsidiary. The majority of Quixx Corp., including Borger Energy Associates and Quixx Power Services, Inc., was sold in October 2006 to affiliates of Energy Investors Funds. In November 2005, Xcel Energy sold Seren's California assets to WaveDivision Holdings, LLC. In January 2006, Xcel Energy sold Seren's Minnesota assets to Charter Communications. Tax Benefits Related to Investment in NRG — Xcel Energy has recognized cumulative tax benefits related to the divestiture of NRG of approximately $1.1 billion. Since these tax benefits are related to Xcel Energy's investment in discontinued NRG operations, they are reported primarily in discontinued operations. Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years due to net operating loss carryforwards. Xcel Energy used $630 million of these deferred tax benefits through 2006, an additional $90 million in 2007, and expects to use approximately $110 million in 2008. The remainder of the tax benefit carry forward is expected to be used over subsequent years.
Xcel Energy's utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas 58 service within their respective jurisdictions and affect Xcel Energy's ability to recover its costs from customers. The historical and future trends of Xcel Energy's operating results have been, and are expected to be, affected by a number of factors, including the following: General Economic Conditions Economic conditions may have a material impact on Xcel Energy's operating results. Management cannot predict the impact of a future economic slowdown, fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital resulting from a general slowdown in future economic growth or a significant increase in interest rates. Sales Growth In addition to the impact of weather, customer sales levels in Xcel Energy's utility businesses can vary with economic conditions, energy prices, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was 1.7 percent in 2007, and 1.8 percent in 2006. Weather-normalized sales growth for firm natural gas utility customers was approximately 0.8 percent in 2007, and (2.8) percent in 2006. Weather-normalized sales for 2008 are projected to grow between 1.8 percent and 2.2 percent for retail electric utility customers and 0.0 percent to 1.0 percent for retail natural gas utility customers. Fuel Supply and Costs Coal Deliverability — Xcel Energy's operating utilities have varying dependence on coal-fired generation. Coal-fired generation comprises between 54 percent and 80 percent of the total annual generation. Approximately 86 percent of the annual coal requirements are supplied from the Powder River Basin in Wyoming. Pension Plan Costs and Assumptions Xcel Energy has significant net pension and postretirement benefit costs that are measured using actuarial valuations. Inherent in these valuations are key assumptions including discount rates and expected return on plan assets. Xcel Energy evaluates these key assumptions at least annually by analyzing current market conditions, which includes changes in interest rates and market returns. Changes in the related net pension and post-retirement benefits costs may occur in the future due to changes in assumptions. For further discussion and a sensitivity analysis on these assumptions, see "Employee Benefits" under Critical Accounting Policies and Estimates. Regulation PUHCA 2005 — The Energy Act significantly changed many federal statutes. The FERC was given authority to review the books and records of holding companies and their nonutility subsidiaries, authority to review service company accounting and cost allocations, and more authority over the merger and acquisition of public utilities. State commissions have similar authority to review the books and records of holding companies and their nonutility subsidiaries. Customer Rate Regulation — The FERC and various state regulatory commissions regulate Xcel Energy's utility subsidiaries. Decisions by these regulators can significantly impact Xcel Energy's results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions. The electric and natural gas rates charged to customers of Xcel Energy's utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy's financial results. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales growth, conservation and DSM efforts and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in rate proceedings. Wholesale Energy Market Regulation — In 2005, a Day 2 wholesale energy market operated by MISO was implemented to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. MISO now centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin. In September 2007, MISO proposed to modify the Day 2 market to establish a regional ASM effective 59 in June 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. NSP-Minnesota and NSP-Wisconsin expect to recover MISO charges through either base rates or various recovery mechanisms. See Note 13 to the consolidated financial statements for further discussion. Capital Expenditure Regulation — Xcel Energy's utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy transmission and distribution systems. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, the CPUC and MPUC approved proposals to recover, through a rate rider, costs to upgrade generation plants and lower emissions, and increased transmission. These rate riders are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis. For wholesale electric transmission services, Xcel Energy has, consistent with FERC policy, implemented or proposed to establish formula rates for each of the utility subsidiaries that will provide annual rate increases as transmission investments increase in a manner similar to the rate riders. Environmental Matters Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital expenditures for environmental compliance. In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and waste were approximately:
Xcel Energy expects to expense an average of approximately $201 million per year from 2008 through 2012 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain. Capital expenditures for environmental improvements at regulated facilities were approximately:
Xcel Energy expects to incur approximately $455 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2008, and approximately $269 million of related expenditures from 2009 through 2012. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado.
See Note 15 to the consolidated financial statements for further discussion of Xcel Energy's environmental contingencies. Generating facilities throughout the Xcel Energy territory are subject to state-only mercury reduction requirements. In Minnesota mercury emissions from A.S. King and Sherburne County generating facilities will be regulated by the 60 Minnesota Mercury Legislation, and in Colorado, seven units are subject to a mercury emissions rule passed by the Colorado Air Quality Control Commission. These facilities, as well as other generating units, were also subject to regulation under the federal CAMR; however, the D.C. Circuit Court of Appeals vacated this rule on Feb. 8, 2008. The EPA requires states to develop implementation plans to comply with the BART/Regional Haze Rules by December 2007. At this time, MPCA is not requiring any BART specific controls that go beyond controls required for CAIR compliance. In response to the BART regulations promulgated by the Colorado Air Quality Control Commission, PSCo submitted its BART alternatives analysis, which had been approved by the CAPCD, as well as the Colorado Air Quality Control Commission during a public hearing in December 2007. CAPCD's BART determinations and corresponding provisions of the regional haze state implementation plan will be submitted to the EPA for approval in 2008. The TCEQ has determined that compliance with CAIR is a substitute for BART for NOx and SO2. In January, NSP-Minnesota made a filing to the MPUC concerning an emissions reduction project at the Sherco generating facility. The improvement project would include generating capacity upgrades for all three units; additional SO2 emission reductions on Units 1 and 2 to improve mercury emission controls; and the installation of additional NOx controls. Impact of Nonregulated Investments In the past, Xcel Energy's investments in nonregulated operations had a significant impact on its results of operations. As a result of the divestiture of NRG and other nonregulated operations, Xcel Energy does not expect that its investments in nonregulated operations to have a significant impact on its results in the future. Inflation Inflation at its current level is not expected to materially affect Xcel Energy's prices or returns to shareholders.
Preparation of the consolidated financial statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements and disclosures, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results reported even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most critical to the portrayal of Xcel Energy's financial condition and results, and that require management's most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the Audit Committee of the Xcel Energy Board of Directors. Xcel Energy is a holding company with rate-regulated subsidiaries that are subject to the FASB "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). SFAS No. 71 provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates could be charged and collected. Xcel Energy's rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of current and future cash flows. Regulatory assets represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. Regulatory liabilities represent incurred or accrued credits that have been deferred because they will be returned to customers in future rates. In other businesses or industries, regulatory assets would be charged to expense and regulatory liabilities would be recorded as income. As of Dec. 31, 2007 and 2006, Xcel Energy has recorded regulatory assets of approximately $1.1 billion and $1.2 billion and regulatory liabilities of approximately $1.4 billion and $1.4 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs, in any such jurisdiction, ceases to be probable, Xcel Energy would be required to charge these assets to current earnings. However, there are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. In addition, deregulation would be 61 a change that occurs over time, due to legal processes and procedures, which could moderate the impact to Xcel Energy's consolidated financial statements. See Note 17 for additional details on regulatory assets and liabilities. NSP-Minnesota owns nuclear generation facilities and regulations require NSP-Minnesota to decommission its nuclear power plants after each facility is taken out of service. Xcel Energy records future plant removal obligations as a liability at fair value. This liability will be increased over time by applying the interest method of accretion to the liability. Due to regulation, depreciation expense is recorded to match the recovery of future cost of decommissioning, or retirement, of its nuclear generating plants. This recovery is calculated using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. Amounts recorded for nuclear AROs, in excess of decommissioning expense and investment returns, both realized and unrealized, cumulatively are deferred through the establishment of a regulatory asset for future recovery pursuant to SFAS No. 71. A portion of the rates charged to customers is deposited into an external trust fund, during the facilities' operating lives, in order to provide for this obligation. The fair value of external nuclear decommissioning trust fund investments are estimated based on quoted market prices for those or similar investments. Realized investment returns from these investments and recovery to date is used by regulators when determining future decommissioning recovery. NSP-Minnesota conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The costs are initially presented in amounts prior to inflation adjustments and then inflated to future periods using decommissioning specific cost inflators. Decommissioning of NSP-Minnesota's nuclear facilities is planned for the period from cessation of operations through 2050 assuming the prompt dismantlement method. The following key assumptions have a significant effect on these estimates:
The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The total obligation for decommissioning currently is expected to be funded 100 percent by a portion of the rates charged to customers, as approved by the MPUC. Decommissioning expense recoveries are based upon the same assumptions and methodologies as the fair value obligations are recorded. In addition to these assumptions discussed previously, assumptions related to future earnings of the nuclear decommissioning fund are utilized by the MPUC in determining the recovery of decommissioning costs. Through utilization of the annuity approach, an assumed rate of return on funding is calculated which provides the earnings rate. 62 With a long period of decommissioning and a funding period over the operating lives of each facility, the ability of the fund to sustain the required payments after inflation while assuring the appropriate investment structure is critical in obtaining the best benefit in the accrual. Currently, an assumption that the external funds will earn a return of 5.4 percent, after tax is utilized when setting recovery by the MPUC. Significant uncertainties exist in estimating the future cost of decommissioning including the method to be utilized, the ultimate costs to decommission, and the planned treatment of spent fuel. Materially different results could be obtained if different assumptions were utilized. Currently, our estimates of future decommissioning costs and the obligation to retire the plants have a significant impact to our financial position. The amounts recorded for AROs and regulatory assets for unrecovered costs are $1,315.1 million and $39.9 million as of December 31, 2007. If different cost estimates, shorter life assumptions or different cost escalation rates were utilized, this ARO and the unrecovered balance in regulatory assets could change materially. If future earnings on the decommissioning fund are lower than that estimated currently, future decommissioning recoveries would need to increase. The significance to our results of operations is reduced due to the fact that we record decommissioning expense based upon recovery amounts approved by our regulators. This treatment reduces the volatility of expense over time. The difference between regulatory funding (including both depreciation expense less returns from the investments fund) and amounts recorded under SFAS No. 143 are deferred as a regulatory asset. Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of effective tax rates. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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