Item 1 - Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
COMPANY OVERVIEW
Xcel Energy was incorporated under the laws of Minnesota in 1909 and is a registered holding company under the PUHCA. Xcel Energy is subject to the regulatory oversight of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include, subject to certain exceptions, a requirement that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. See additional discussion of PUHCA requirements under Factors Affecting Results of Continuing Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis under Item 7.
In 2004, Xcel Energy continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline company, these companies comprise our continuing regulated utility operations. Discontinued utility operations include the activity of Viking, which was sold in January 2003; BMG, which was sold in October 2003; and Cheyenne, which was sold in January 2005.
Xcel Energy’s nonregulated subsidiaries in continuing operations include UE, Eloigne and Planergy. Planergy closed and began selling a majority of its business operations in 2003 with all operations ceasing in 2004. On March 2, 2005, Xcel Energy agreed to sell UE. See further discussion under Nonregulated Subsidiaries.
During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc. (broadband communications services). Earnings per share for 2004 of $0.87 includes revisions to the impairment reserve associated with Seren, as well as the completed sale of Cheyenne, compared to the previously reported earnings per share of $0.97.
During 2003, Xcel Energy divested its ownership interest in NRG. On May 14, 2003, NRG and certain of its affiliates filed for bankruptcy to restructure their debt. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. Xcel Energy made payments of $752 million to NRG in 2004. During 2003, the board of directors of Xcel Energy also approved management’s plan to exit certain businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (an international independent power producer, primarily in Argentina) and e prime inc. (a natural gas marketing and trading company). NRG, Xcel Energy International, e prime and Seren are accounted for as a component of discontinued operations.
For more information regarding Xcel Energy’s discontinued operations, see Note 3 to the Consolidated Financial Statements.
Xcel Energy’s executive offices are located at 800 Nicollet Mall, Minneapolis, Minn. 55402. Its Web site address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its Web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. In addition, the Xcel Energy Guidelines on Corporate Governance and Code of Conduct also are available on its Web site.
NSP-Minnesota
NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. Prior to 2000, the regulated utility operations currently conducted by NSP-Minnesota were conducted by the legal entity now operating under the name Xcel Energy. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. 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 gas utility service to approximately 454,000 customers.
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 holds NSP-Minnesota’s interest in the NMC. NSP-Minnesota owned NSP Financing I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Sept. 15, 2003.
NSP-Wisconsin
NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 240,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory to approximately 97,000 customers. See the discussion of the integrated management of the electric production and transmission system of NSP-Wisconsin under NSP-Minnesota, discussed previously.
NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.
PSCo
PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.
PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; PSRI, which owns and manages permanent life insurance policies on certain current and former employees; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant. PS Colorado Credit Corp., a finance company that was owned by PSCo and financed certain of PSCo’s current assets, was dissolved in 2002. PSCo owned PSCo Capital Trust I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Dec. 29, 2003.
SPS
SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. SPS serves approximately 395,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprise approximately 35 percent of the total Kwh sales in 2004. A major portion of SPS’ retail electric operating revenues is derived from operations in Texas. SPS owned a direct subsidiary, Southwestern Public Service Capital I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Jan. 5, 2004.
Other Regulated Subsidiaries
WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.
ELECTRIC UTILITY OPERATIONS
Electric Utility Trends
Overview
Utility Industry Growth - After a decade of cost cutting and efficiency gains in anticipation of industry restructuring and competition; areas of growth for the utility industry are limited. The most significant areas for earnings growth include increasing regulated rates, increased investment in rate base, diversification, acquisition or modification of rate structures to implement performance-based rates. Though remaining open to all opportunities to increase shareholder value, Xcel Energy intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers and rate case filings with state and federal regulators to increase rates congruent with increasing costs of operations associated with such investments.
Utility Restructuring and Retail Competition - The structure of the utility industry has been subject to change. Merger and acquisition activity in the past had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001. All investor-owned utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition. These states included many of the jurisdictions in which the Xcel Energy Utility Subsidiaries operate. Much of Texas has implemented retail competition, but it is presently limited to utilities within the Electric Reliability Council of Texas. Under the current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas on or after Jan. 1, 2007. However, SPS has no plan to implement retail competition in its service area. 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. As a result of the failure of the California power market structure and nonregulated investments of many utilities, as well as other factors, most utility retail market restructuring has ceased. No significant activity has occurred or is expected to occur in the retail jurisdictions in which Xcel Energy Utility Subsidiaries operate, except as noted previously.
The retail electric business does face some competition as industrial and large commercial customers have some 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 face these challenges, these subsidiaries believe their rates are competitive with currently available alternatives.
Summary of Recent Federal Regulatory Developments
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of Xcel Energy’s Uutility Subsidiaries. State and local agencies have jurisdiction over many of Xcel Energy’s activities, including regulation of retail rates and environmental matters.
Market Based Rate Authority - The FERC regulates the wholesale sale of electricity. In addition to FERC’s traditional cost of service methodology for determining the rates allowed to be charged for wholesale electric sales, in the 1990’s FERC began to allow utilities to make sales at market-based rates. In order to obtain market-based rate authorization from the FERC, utilities such as the Utility Subsidiaries have been required to submit analyses demonstrating that they did not have market power in the relevant markets. Xcel Energy and the Utility Subsidiaries have been granted market-based rate authority by FERC.
In November 2001, after the market disruptions in California and other regions, the FERC issued an order under Section 206 of the Federal Power Act initiating a generic investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates. In November 2003, the FERC issued a final order requiring amendments to the market-based wholesale tariffs of all FERC jurisdictional electric utilities to impose new market behavior rules and requiring submission of compliance tariff amendments in December 2003. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each made a timely compliance filing. Violations of the new tariffs could result in the loss of certain wholesale sales revenues or the loss of authority to make sales at market-based rates.
In 2004, FERC initiated a new proceeding on future market-based rate authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. The FERC adopted a new interim methodology to assess generation market power and modified measures to mitigate market power where it is found. The FERC upheld and clarified the interim requirements on rehearing in an order issued on July 8, 2004. This methodology is to be applied to all initial market-based rate applications and triennial reviews. Under this methodology, the FERC has adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) to assess market power. Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power. An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power.
As required by the FERC, Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005. This analysis demonstrated that all of the Utility Subsidiaries, with the exception of PSCo, passed the pivotal supplier analysis in their own control areas and all adjacent markets, but that all failed the market share analysis in their own control areas, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets. It is accordingly expected that the FERC will set the market-rate authorizations for the Utility Subsidiaries and Xcel Energy for investigation and hearing under Section 206 of the Federal Power Act. At that time, the Utility Subsidiaries expect to submit a delivered-price test analysis to support the continuance of market-based rate authority in their control areas. Xcel Energy also expects that upon the commencement of the MISO Day 2 market (see Electric Transmission Rate Regulation, below for further discussion), NSP-Minnesota and NSP-Wisconsin will be analyzed as part of the larger MISO market, and that those companies will pass both of the FERC’s indicative screens in the larger MISO market. Xcel Energy does not expect the mitigation measures imposed, if any, to have a significant financial impact on its commodity marketing operations.
In order to enable it and interested parties to monitor each individual utility’s market-based rate authority, the FERC on Feb. 10, 2005 issued a final rule requiring that a utility with market-based rate authority file reports notifying the FERC of changes in status (e.g., additions of certain generating resources) that reflect a departure from the characteristics that the FERC relied upon in granting that utility market-based rate authority within thirty days of the occurrence of a triggering event.
Electric Transmission Rate Regulation - The FERC also regulates the rates charged and terms and conditions for electric transmission services. Since 1996, the FERC has required the Utility Subsidiaries to provide open access transmission service at rates and tariffs on file with the FERC. In addition, FERC policy encourages utilities to turn over the functional control over 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, which began RTO operations in early 2002. SPS is a member of the SPP, which proposes to begin RTO operations in October 2005. SPS has been a member of SPP’s regional transmission tariff since 2001. Each RTO separately files for regional transmission tariff rates for approval by FERC. All members within that RTO are then subjected to those rates. PSCo is currently participating with other utilities in the development of an RTO.
Generation Interconnection Rules - In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreements for interconnection of new electric generators of 20 megawatts or more to the transmission systems of all FERC-jurisdictional electric utilities, including Xcel Energy’s Utility Subsidiaries. The FERC also established pricing rules for interconnections and related transmission system upgrades, which allow the transmission-owning utility to require the
interconnecting customer to fund the interconnection costs and network upgrades required by the new generator, but require the transmission utility to provide transmission service credits, with interest, for the full amount of prepayment. The FERC required compliance filings for detailing proposed changes to Xcel Energy Utility Subsidiaries’ tariff, the MISO regional tariff, and the SPP regional tariff, which will govern most generation interconnections to the Xcel Energy Utility Subsidiaries’ transmission system. In October 2004, the FERC accepted proposed tariff changes for Xcel Energy’s Utility Subsidiaries, subject to certain conditions. In November 2004, the Utility Subsidiaries submitted a compliance filing. In December 2004, the FERC issued further modifications to the interconnection rules on rehearing and required Xcel Energy’s Utility Subsidiaries to submit a further compliance filing by February 2005. The required compliance filing was submitted on Feb. 18, 2005.
NSP-Minnesota
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of 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, 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 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. NSP-Minnesota 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. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices and is a transmission-owner member of the MISO RTO.
The MEQB is empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB. 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.
Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms - NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota jurisdictions 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 general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.
The MPUC has opened an investigation to consider the continuing usefulness of fuel clause adjustments for electric utilities in Minnesota. No action has been proposed. The MPUC has the authority to disallow recovery of certain costs if it finds the utility was not prudent in its procurement activities.
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.
Performance-Based Regulation - In December 2003, the MPUC voted to approve 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. All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC also approved NSP-Minnesota’s proposal to recover prudent costs of the projects through a rate adjustment provision applicable to retail electric rates 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.
Pending and Recently Concluded Regulatory Proceedings - FERC
MISO Operations - In August 2000, NSP-Minnesota and NSP-Wisconsin joined the MISO. In December 2001, the FERC approved the MISO as the first RTO in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 KVand above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.
On March 31, 2004, the MISO filed its proposed TEMT, which would establish regional wholesale energy markets using locational marginal cost pricing and FTRs. NSP-Minnesota and NSP-Wisconsin’s generation plants and transmission systems would operate subject to the TEMT. The MISO proposed a Dec. 1, 2004 effective date.
On May 26, 2004, the FERC issued an initial procedural order. The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005. NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004. Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004. The other GFAs are not disputed. The primary disputed issues related to responsibility for TEMT charges for loads served under the GFAs. On Sept. 16, 2004, the FERC issued an order ruling that certain GFAs would be “carved out” of the MISO market but that transmission owners would be subject to the TEMT charges for other GFAs. The FERC has not issued a final decision on rehearing. On Jan. 13, 2005, several transmission-owning members of the MISO, including NSP-Minnesota and NSP-Wisconsin, filed revisions to the MISO tariff to recover TEMT charges from the customers subject to the “carved out” GFAs, effective March 1, 2005. NSP-Minnesota and NSP-Wisconsin expect to file for rate changes under certain GFAs to recover TEMT charges from these GFA customers later in 2005.
On Aug. 6, 2004, after completion of the GFA hearings and submission of the ALJ report, the FERC issued its initial substantive order regarding the TEMT. The FERC approved the TEMT and reaffirmed the March 1, 2005 effective date, but ordered various changes to the filed tariff. On Sept. 7, 2004, numerous requests for rehearing were filed contesting various FERC decisions. On Nov. 8, 2004, the FERC issued its order on rehearing largely upholding the August 6th order. On or before Jan. 6, 2005, several appeals of the two FERC orders were filed with the District of Columbia Court of Appeals. Xcel Energy does not believe the outcome of the appeals will have a material financial impact. In addition, various parties, including NSP-Minnesota and NSP-Wisconsin, have documented their concerns to MISO regarding MISO’s readiness to initiate the new energy market on March 1, 2005. On Jan. 27, 2005, MISO announced a delay in the full market start date until April 1, 2005.
Xcel Energy opposes certain aspects of the TEMT-related implementation practices as presently designed, and believes the MISO should implement the new market mechanisms only after it demonstrates that it has fully developed all operating procedures necessary to protect reliability. Xcel Energy cannot at this time estimate the total financial impact of the new market structure. Xcel Energy also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the MISO market to commence on the new April 1, 2005 start date, as proposed.
Wisconsin Public Service Corp. vs. MISO - On Dec. 27, 2004, Wisconsin Public Service Corp. (WPS) filed a complaint with the FERC alleging that certain FTRs allocated to NSP-Minnesota in MISO’s FTR nomination and allocation process, associated with the implementation of the new MISO TEMT, improperly granted NSP-Minnesota FTRs to the detriment of WPS. WPS alleged the FTR allocation to NSP-Minnesota would increase costs to WPS and its customers. WPS requested accelerated processing of the complaint. On Jan. 15, 2005, MISO and NSP-Minnesota filed answers asking that the WPS complaint be dismissed. The complaint is now pending resolution by the FERC. In a related matter, WPS appealed to the U.S. District Court for the District of Columbia previous FERC orders upholding NSP-Minnesota’s right to the underlying transmission service at issue in the MISO FTR allocation. The appeal is scheduled to be heard by the court in April 2005.
MISO Long Term Pricing - On Nov. 18, 2004, FERC issued an order approving portions of a plan providing for continued use of “license plate” rates for the MISO/PJM region, but rejecting proposed transition payments. FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism. The replacement compliance filings were submitted Nov. 24, 2004, to be effective December 1, 2004. The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $117,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in the first three months of 2005. MISO and PJM are required to update the SECA charges effective April 1, 2005. The magnitude of the new charges and payments is unknown at this time, but is expected to be similar to the charges and payments for the first three months of 2005.
Various parties sought rehearing of the Nov. 18, 2004 order and/or filed objections to the Nov. 24, 2004 SECA compliance filings. On Feb. 10, 2005, the FERC issued an order accepting the SECA filings effective Dec. 1, 2004, subject to refund, and set the proposals for hearings. Therefore, the final resolution of the SECA issue and its impact on NSP-Minnesota and NSP-Wisconsin, is not fully known at this time.
Pending and Recently Concluded Regulatory Proceedings - MPUC
Minnesota Service Quality Investigation - In 2002, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly and annual basis, subject to penalty for not meeting threshold requirements, under the terms of the merger settlement agreements.
In 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement, which was approved with modifications by the MPUC in January 2004. The settlement required NSP-Minnesota to refund $1 million to customers in Minnesota, which was paid in 2004. In addition, it required NSP-Minnesota to incur at least $15 million of costs for actions to improve system reliability above amounts being recovered in 2004 rates by Jan. 1, 2005, for which $19 million was expended in 2004. The MPUC modified the settlement to include an additional under-performance payment for any future finding of inaccurate reliability data.
NRG Tax Complaint - In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. In August 2004, the MPUC decided not to pursue this complaint. The MPUC affirmed the long-standing precedent to view each utility as a stand-alone business that does not experience positive or negative effects from its affiliates. The customer filed an appeal of this decision on Jan. 7, 2005, and NSP-Minnesota filed a responsive statement of the case on Jan. 18, 2005. The Attorney General’s office petitioned to file an advisory brief to the customer’s case.
Renewable Transmission Cost Recovery - In 2002, NSP-Minnesota filed for MPUC approval to establish an RCR adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources. The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information. The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003. In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing. NSP-Minnesota then filed for approval to recover annual additional transmission costs from May 2004 to December 2004, which were approximately $6 million. The request was approved and the RCR was implemented Dec. 1, 2004. NSP-Minnesota collected approximately $0.2 million in 2004. NSP-Minnesota submitted a filing to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005 in February 2005, seeking recovery of $12.9 million of additional revenues in 2005.
Time-of-Use Pilot Project - As required by MPUC orders, NSP-Minnesota has been working to develop a time-of-use pilot project that would attempt to measure customer response and conservation potential of such a program. This pilot project explores providing customers with pricing signals and information that could better inform customers about their use of electricity and its costs. NSP-Minnesota has petitioned the MPUC for recovery of program costs. The 2002 program costs were approximately $2 million. The Department of Commerce has supported deferred accounting to provide for recovery of prudent, otherwise unrecovered and appropriate costs, subject to a normal prudence review process. The Office of the Attorney General has argued that cost recovery should be denied for several reasons. A MPUC hearing was held in January 2004 and requested NSP-Minnesota to further substantiate the prudence and appropriateness of the costs incurred. The MPUC has voted to allow recovery of the program costs. An order of the
MPUC is expected in early 2005.
MISO Cost Recovery Petition - On Dec. 18, 2004, NSP-Minnesota filed a petition to seek recovery of all net costs associated with the implementation of the MISO TEMT through its FCA mechanism. Under the current mechanism, NSP-Minnesota is allowed full recovery of its fuel and purchased energy costs. The proposal would allow recovery of locational marginal pricing market costs, including congestion and marginal loss costs, which would be netted by FTR revenues and revenues received that are related to marginal compensation loss costs, as well as MISO energy market operations costs. NSP-Minnesota has sought recovery effective with the beginning of the Day 2 energy market, scheduled for April 1, 2005 and the deferral of costs incurred prior to MPUC action. A decision is expected in the second quarter of 2005.
Capacity and Demand
Assuming normal weather during 2005, system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2005 is listed below.
The peak demand for the NSP System typically occurs in the summer. The 2004 system peak demand for the NSP System occurred on July 21, 2004.
Energy Sources and Related Initiatives
NSP-Minnesota expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options and phased expansion of existing generation at select power plants to meet its net dependable system capacity requirements.
Purchased Power - NSP-Minnesota has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, 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 firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide each utility’s reserve obligation, 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.
NSP System Resource Plan - On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with MPUC. The resource plan projects a need for an additional 3,100 MW of electricity resources during the next 15 years, based on an anticipated growth in demand of 1.61 percent annually, or approximately 170 MW per year, during the period. The resource plan:
• identifies the need for adding up to 1,125 MW of new base-load electricity generation by 2015;
• recommends a new resource acquisition process that includes multiple options for consideration, including generation built by NSP-Minnesota;
• recommends increasing energy-saving goals for demand-side energy management programs by nearly 17 percent;
• recommends extending the operating licenses for the Prairie Island and Monticello nuclear plants by 20 years (on Jan. 18, 2005, NSP-Minnesota applied for a certificate of need in Minnesota for a dry spent-fuel storage facility at the Monticello plant, and plans to file an application with the federal government to extend the Monticello plant’s license and to make similar filings for the Prairie Island plant in 2008);
• assumes nearly 1,700 MW of wind power with most developed on NSP-Minnesota’s system;
• identifies the need for obtaining up to 550 MW of new power resources for peak usage times by 2015 depending on the amount and timing of any base-load resources acquired; and
• cites the importance of ensuring that sufficient transmission resources are available to move electricity from generation sources.
The MPUC initially established a comment period on NSP-Minnesota’s proposed resource acquisition strategy with comments due Dec. 28, 2004 and reply comments due Jan. 17, 2005. The Department of Commerce has requested an extension to June 1, 2005 to file comments on the overall resource plan. NSP-Minnesota did not object to this request.
NSP-Minnesota Transmission Certificates of Need - In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million. The MEQB granted a routing permit for the first major transmission facilities in the development program in 2004. The remaining route permit proceedings are underway and expected to be completed in 2005. In 2003, the MPUC also approved an RCR adjustment that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism that started in 2004. See the Pending and Recently Concluded Regulatory Proceedings - MPUC, Renewable Transmission Cost Recovery section for further discussion.
Purchased Transmission Services -NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to NSP System native load customers, which are retail and wholesale load obligations with terms of more than one year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.
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 17 to the Consolidated Financial Statements.
Nuclear power plant operation produces gaseous, liquid and solid radioactive substances. The discharge and handling of such substances are controlled by federal regulation. High-level radioactive substances primarily include used nuclear fuel. Low-level radioactive substance 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 its low-level radioactive substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance), and the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive substance from out of state. Envirocare, Inc. operates the Clive facility. NSP-Minnesota has an annual contract with Barnwell, while NSP-Minnesota uses the Envirocare facility through various low-level substance processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed lives, if off-site low-level 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 substances. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear substance 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 substances at a permanent storage or disposal facility. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 - Legal Proceedings and Note 17 to the Consolidated Financial Statements for further discussion of this matter. The National Commission on Energy Policy, a privately funded coalition, has recommended that the federal government continue to pursue a nuclear waste storage facility in Nevada’s Yucca Mountain and urged them to build multiple above ground dry cask storage sites in the eastern and western United States in case the Yucca Mountain project is delayed or cancelled.
NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full. On May 29,
2003, the Minnesota Legislature enacted legislation that allows NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with NRC expire in 2013 and 2014. This will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. See Note 17 in the Consolidated Financial Statements for further discussion of the matter.
Visual Inspections - Required visual inspections have been performed on the Prairie Island Unit 2 upper and lower reactor vessel heads, and the Unit 1 upper head. Reactor vessel heads for both units were found to be in compliance with all NRC requirements. Xcel Energy has placed orders and plans to replace the reactor vessel upper heads of Prairie Island Unit 2 during the 2005 refueling outage and Unit 1 during the 2006 refueling outage.
Private Fuel Storage (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. The NRC license review process includes formal evidentiary hearings before an ASLB and opportunities for public input. Evidentiary hearings were held in 2000 and 2002. In December 2004, the state of Utah claimed a representative of the DOE stated that it would not accept waste sealed in the type of containers planned by PFS. PFS responded by providing documents that the DOE will accept fuel stored in dry casks. The ASLB ruled in February 2005 that it would not reopen the hearing record to consider this issue, indicating it was instead worthy of NRC consideration. The ASLB also issued its decision on the last remaining issue regarding the facility, finding in favor of PFS. NRC commissioners will decide whether to officially issue a license for the site. The state of Utah has asked the U.S. Supreme Court to consider whether the state of Utah can block PFS from locating a spent fuel storage facility in the state, if the federal government has exclusive control over the storage and transportation of nuclear waste. The court neither accepted nor declined the appeal filed by the state of Utah, but has sought additional information. Due to uncertainty regarding NRC and other regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.
Prairie Island Steam Generator Replacement - In the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the steam generators at Unit 1 of the Prairie Island nuclear generating plant. The steam generators at Unit 2 have not yet been replaced, but will be inspected during a scheduled 2005 outage.
NSP-Minnesota Nuclear Plant Re-licensing - On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005 seeking a certificate of need for dry spent fuel storage and plans to file an application in 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello re-licensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years.
Nuclear Management Co. (NMC) - During 1999, NSP-Minnesota, Wisconsin Electric Power Co., WPS and Alliant Energy Corp. established NMC. The objective in creating NMC was to enhance operational excellence in nuclear plant operations by consolidating resources, combining talent and gaining efficiencies. The Consumers Power subsidiary of CMS Energy Corp. joined NMC during 2000, and transferred operating authority for the Palisades nuclear plant to NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 MW. WPS is seeking regulatory approval to sell its Kewaunee Nuclear Power Plant to a subsidiary of Dominion Resources, Inc., and may not continue to participate in NMC. In addition, Alliant Energy has announced that it intends to seek bids to potentially sell the Duane Arnold nuclear plant and, therefore, may not continue to participate in the NMC.
The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to NMC, formally establishing NMC as an operating company. NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including NSP-Minnesota, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs. Existing personnel continue to provide day-to-day plant operations, with the additional benefit of implementing best practices from all NMC-operated plants for improved safety, reliability and operational performance.
For further discussion of nuclear issues, see Notes 16 and 17 to the Consolidated Financial Statements.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.
*Includes refuse-derived fuel and wood
Fuel Sources - The NSP System normally maintains between 30 and 50 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota and NSP-Wisconsin’s major coal-fired generating plants are approximately 13.1 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 97 percent of 2005 coal requirements and up to 59 percent of the 2006 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.
NSP-Minnesota and NSP-Wisconsin expect that all of the coal burned in 2005 will have an average sulfur content of less than 0.5 percent. The NSP System has contracts for a maximum of 22.9 million tons of low-sulfur coal for the next 3 years. The contracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1 Minnesota oil refinery, with expiration dates ranging between 2006 and 2007. The NSP System could purchase approximately 20 percent of coal requirements in the spot market in 2006 if spot prices are more favorable than contracted prices.
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.
• Current nuclear fuel supply contracts cover 46 percent of uranium requirements through 2006 with no coverage of requirements for 2007 and beyond.
• Current contracts for conversion services requirements cover 32 percent of the requirements through 2007 with no coverage of requirements for 2008 and beyond.
• Current enrichment services contracts cover 55 percent of the requirements through 2010 with no coverage of requirements for 2011 and beyond. These current contracts expire at varying times between 2005 and 2010.
• Fuel fabrication for Monticello is covered through 2010. Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and through 2005 for Prairie Island Unit 2. Both Prairie Island Units are not contracted for fuel fabrication beyond those dates. NSP-Minnesota and NMC are currently in negotiations with Westinghouse to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts.
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 and enrichment services are currently being negotiated that would provide additional supply requirements through 2010 for uranium and enrichment services.
The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel. The NSP System has current fuel oil inventory adequate to meet anticipated 2005 requirements and also has access to the spot market to buy more oil, if needed.
Commodity Marketing Operations
NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of NSP-Minnesota. NSP-Minnesota uses physical and financial instruments to minimize commodity
price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. NSP-Minnesota also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices. See additional discussion under Item 7A - Quantitative and Qualitative Disclosures About Market Risk.
NSP-Wisconsin
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - Retail rates, services and other aspects of NSP-Wisconsin’s operations are subject to regulation 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 and retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, 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.
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.
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 outside a prescribed range, 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 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.
Pending and Recently Concluded Regulatory Proceedings - FERC
MISO - See the discussion of the MISO activity under NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings.
Pending and Recently Concluded Regulatory Proceedings - PSCW
NSP-Wisconsin 2005 Fuel Cost Recovery Filing - On Aug. 2, 2004, NSP-Wisconsin filed an application with the PSCW to reopen its 2004 rate case for the limited purpose of resetting 2005 electric fuel monitoring costs, and to authorize an increase in Wisconsin retail electric rates to recover forecast increases in fuel and wholesale market purchased energy costs. In its August application, NSP-Wisconsin indicated an increase of $17.3 million was necessary to avoid under-recovering its 2005 fuel costs based on the most recent forecast. On Dec. 29, 2004, the PSCW issued a final order in the case, authorizing an annual increase of $18.6 million effective Jan. 1, 2005 and resetting the 2005 electric fuel monitoring costs. Because the PSCW used updated market prices for natural gas, oil and purchased power to forecast 2005 costs, the amount of the increase authorized was greater than initially requested by NSP-Wisconsin.
MISO Cost Recovery - In 2005, NSP-Wisconsin filed a petition along with other Wisconsin utilities seeking deferred accounting treatment for net costs of MISO Day 2 energy market implementation, similar to relief already granted to Wisconsin Public Service Company in their most recent rate case. In addition, the utilities requested that the PSCW begin the process to change their fuel and energy cost recovery rules to accommodate MISO Day 2 charges.
Capacity and Demand
Assuming normal weather during 2005, system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2005 is listed below.
The peak demand for the NSP System typically occurs in the summer. The 2004 system peak demand for the NSP System occurred on July 21, 2004.
Energy Sources and Related Initiatives
NSP-Wisconsin operates an integrated system with NSP-Minnesota. See a discussion of the system energy sources under NSP-Minnesota Energy Sources and Related Initiatives discussed previously.
Fuel Supply and Costs
NSP-Wisconsin operates an integrated system with NSP-Minnesota. See a discussion of the system energy sources under NSP-Minnesota Fuel Supply and Costs discussed previously.
PSCo
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - PSCo is subject to the jurisdiction of the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo 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. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices.
Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms - PSCo has several retail adjustment clauses that recover fuel, purchased energy and resource costs:
• Electric Commodity Adjustment (ECA) - The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA then provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate. The formula rate is revised annually and collected or refunded in the following year, if necessary.
• Incentive Cost Adjustment (ICA) and Interim Adjustment Clause (IAC) - The ICA allowed for an equal sharing between retail electric customers and shareholders of certain fuel and purchased energy costs and expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs is being amortized over the period June 1, 2002 through March 31, 2005. For 2003, the IAC provided for the recovery of prudently incurred fuel and energy costs not included in electric base rates.
• Purchased Capacity Cost Adjustment (PCCA) - The PCCA, which became effective June 1, 2004, allows for recovery of purchased capacity payments to certain power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms. The PCCA rider provided recovery of $18 million of capacity costs in 2004 and is expected to provide recovery of $31 million in 2005 and $20 million in 2006. The PCCA will expire on Dec. 31, 2006. Purchased capacity costs both from contracts included within the PCCA and from contracts not included within the PCCA are expected to be eligible for recovery through base rates, when PSCo files its next general rate case.
• Steam Cost Adjustment (SCA) - The SCA allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised at least annually to coincide with changes in fuel costs.
• Air-Quality Improvement Rider (AQIR) - The AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
• Demand-Side Management Cost Adjustment (DSMCA) - The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA.
PSCo recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC. In February 2004, the FERC approved a revised wholesale fuel adjustment clause for PSCo, which PSCo submitted as part of a settlement agreement with certain of its wholesale customers contesting past charges under PSCo’s prior fuel adjustment clause.
Performance-Based Regulation and Quality of Service Requirements - The CPUC established an electric and natural gas PBRP under which PSCo operates. The major components of this regulatory plan include:
• an annual electric earnings test with the sharing between customers and shareholders of earnings in excess of the following limits:
• all earnings above an 11-percent return on equity for 2001 and a 10.50-percent return on equity for 2002;
• no earnings sharing for 2003 as PSCo established new rates in its general rate case; and
• an annual electric earnings test with the sharing of earnings in excess of the return on equity for electric operations of 10.75 percent for 2004 through 2006;
• an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006; and
• a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2007.
PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually.
• In 2002, PSCo did not earn a return on equity in excess of 10.5 percent, so no refund liability was recorded. PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance. In December 2004, the CPUC approved a settlement resolving the earnings test for 2002.
• In 2003, PSCo did not achieve the performance targets for the QSP electric service unavailability measure or the customer complaint measure. Targets were met for the natural gas QSP. There was no sharing of earnings for 2003, as PSCo established new rates in its general rate case.
• In 2004, PSCo does not anticipate earning a return on equity in excess of 10.75 percent and did not record a refund liability. QSP results will be filed with the CPUC in April 2005. An estimated customer refund obligation under the electric QSP plan was recorded in 2004 related to the electric service unavailability measure. No refund under the natural gas QSP is anticipated.
Pending and Recently Concluded Regulatory Proceedings - FERC
PSCo and SPS FERC Transmission Rate Case - On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT). PSCo and SPS are seeking an increase in annual transmission service and ancillary services revenues of $6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, of which $3.0 million is attributable to PSCo. In December 2004, the FERC suspended the filing and delayed the effective date of the proposed increase to May 20, 2005. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The case has been set for hearing and settlement procedures.
California Refund Proceeding - A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo supplied energy to these markets during this period and has been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an ALJ to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the state was holding funds owed to suppliers.
Certain California parties sought rehearing of this decision. Among other things, they asserted that the refund effective date should be set at an earlier date. They have based this request in part on the argument that the use by sellers of certain trading strategies in the California market resulted in unjust and unreasonable rates, thereby justifying an earlier refund effective date. The FERC subsequently allowed the purchasing parties to request from sellers, including PSCo, additional information regarding the market participants’ use of certain strategies and the effect those strategies may have had on the market. Based on the additional information they obtained, these purchasing entities argued to the FERC that use of these strategies did justify an earlier refund effective date. These California entities have contended that PSCo would owe approximately $17 million in refunds, if the FERC set the earlier refund effective date. In October 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification of how refunds should be determined for the previously set refund period. Certain California parties appealed the FERC’s decision not to establish an earlier refund effective date to the United States Court of Appeals for the Ninth Circuit.
In a related case, certain California parties also appealed the FERC orders dismissing a complaint by the California Attorney General challenging market-based rates as inconsistent with the Federal Power Act. The California Attorney General also argued that wholesale sellers, including PSCo, were violating their market-based rate authorizations by not reporting their market-based sales on an individual transaction basis. Prior to a clarification of its rules, most sellers, including PSCo, reported their transactions on an aggregate basis. On Sept. 9, 2004, the United States Court of Appeals for the Ninth Circuit issued an opinion rejecting the California Attorney General’s general challenge to market-based rates, but agreeing with its challenge regarding the failure to report individual transactions. It remanded the case to the FERC to consider action to take to address these failures and indicated that the FERC could require refunds. Several of the intervenors in this appeal filed a petition for rehearing of this decision in October 2004. The rehearing request is pending at the U.S. Court of Appeals for the Ninth Circuit.
Further, several actions in California state courts involve similar issues, challenging wholesale sales made at market-based rates in the California markets. These proceedings, filed in federal court in California and in the Superior Court of the State of California for the County of San Francisco, allege, among other causes of action, violations of California Business and Professions Code Section 17200 by Xcel Energy and a number of other suppliers and traders of wholesale power. The essence of the complaints are that the defendants allegedly manipulated the market for electricity by fixing prices and restricting supply into the California markets, or by engaging in other conduct for the purpose of artificially inflating the price of electricity, and/or by charging unlawful prices for such electricity. Although these proceedings were dismissed, and appeals were denied by the Ninth Circuit, Petitions for Writ of Certiorari have been filed with the United States Supreme Court. The Supreme Court has not yet acted on the Writ Petitions.
PSCo has accrued its estimated minimum liability related to these cases. Because of the low volume of sales that PSCo had into California, its exposure is estimated to be approximately $7 million. The FERC has encouraged buyers and sellers in the organized California markets to try to resolve these cases through settlement, and PSCo is presently having settlement negotiations with various California entities to try to reach a comprehensive resolution of these cases.
FERC OMOI Compliance Audit - On October 28, 2004, the OMOI sent a letter to Xcel Energy stating that OMOI had initiated a routine audit of PSCo compliance with various FERC regulations, including PSCo’s OATT, FERC’s Order No. 889 standards of conduct rules and PSCo’s code of conduct for transactions in power and non-power goods with affiliates with market-based rates. Similar compliance audits of other utilities have resulted in compliance orders and, in certain cases, civil penalties.
FERC Investigation Against Wholesale Electric Sellers - On June 25, 2003, the FERC issued two show cause orders addressing alleged improper market behavior in the California electricity markets. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market behavior. The FERC initiated proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California ISO, have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the California ISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. Subsequent to the show cause order, PSCo provided information to the FERC staff showing PSCo did not engage in circular scheduling. Subsequently, certain California parties requested that FERC make PSCo subject to the show cause proceeding addressing
partnerships and expand the scope of the show cause order addressing gaming and/or anomalous market behavior to have PSCo address an allegation that it engaged in another of the specified activities, namely “load shift.”
On Aug. 29, 2003, the FERC trial staff filed a motion to dismiss PSCo from the show cause proceeding. On Jan. 22, 2004, the FERC granted motions to dismiss certain parties, including PSCo, of the show cause proceedings addressing the use of gaming or anomalous market behavior. The FERC on that same day in a separate order also rejected requests to expand the scope of the show cause proceedings addressing partnerships. On Feb. 23, 2004, certain California parties sought rehearing of the FERC’s order addressing gaming or anomalous market behavior. That matter is still pending before the FERC. Certain California parties also filed appeals of the FERC’s order addressing partnerships, and that matter is pending.
Pacific Northwest FERC Refund Proceeding - In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed the total amount of transactions with PSCo subject to refund are $34 million.
On June 25, 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. On Nov. 10, 2003, in response to requests for rehearing, FERC reaffirmed this ruling to terminate the proceeding without refunds. Certain purchasers have filed appeals of the FERC’s orders in this proceeding.
Pending and Recently Concluded Regulatory Proceedings - CPUC
Electric Department Earnings Test and CPUC Reliability Inquiry - As a part of PSCo’s annual electric earnings test, the CPUC opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital are appropriate.
In December 2004, the CPUC approved a settlement resolving the earnings test and providing for PSCo’s recovery of the actual cost of debt. It requires PSCo to spend an incremental $38 million, which will be included in rate base in future rate filings, in capital expenditures over the next three years to improve system reliability and contribute $2 million to Energy Outreach Colorado, a non-profit energy assistance organization.
Quality of Service Plan - The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2004, PSCo filed its calendar year 2003 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures. PSCo did not achieve the 2003 performance targets for the electric service unavailability measure or the customer complaint measure. Additionally, PSCo filed revisions to its previously filed 2002 electric QSP results for the service unavailability measure. Based on the revised results, PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.
As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. PSCo posted the bill credits to retail customer accounts in the third quarter of 2004. For calendar year 2004, PSCo has evaluated its performance under the QSP and has recorded a liability of $11 million. Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met. The maximum potential bill credit obligation for the same period related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million.
Incentive Cost Adjustment and Interim Adjustment Clause - PSCo’s ICA mechanism was in place for periods prior to 2003. The costs included in the ICA were subject to review by the CPUC. In a CPUC docket reviewing the 2001 ICA, the CPUC approved a settlement that, among other things, provided for a prospective revenue adjustment related to the maximum allowable natural gas hedging costs that would be a part of the electric commodity adjustment for 2004, which reduced 2004 rates by $4.6 million. In 2004,
the CPUC approved the 2002 fuel and purchased energy costs reflected in the ICA. PSCo agreed to amortize the 2002 ICA costs over the period of June 2002 through March 2005. In 2003, PSCo’s prudently incurred fuel and purchased energy costs were fully recoverable under the IAC and are still subject to a future review by the CPUC. On Aug. 2, 2004, PSCo applied to the CPUC for approval of its 2003 fuel and purchased energy costs. This application is pending before the CPUC.
Electric Trading Docket - As part of the settlement of the 2002 PSCo general rate case, the parties agreed that PSCo would initiate a docket regarding the status of wholesale electric trading after 2004. The proceeding was initiated on Jan. 30, 2004. PSCo’s testimony proposed certain revisions to the business rules governing trading transactions; to continue electric trading on both a generation book and commodity book basis; to establish a defined trading benefit for electric retail customers and to begin trading natural gas as a risk mitigation measure in support of its electric trading. On July 8, 2004, the staff of the CPUC filed testimony regarding electric trading. The staff raised issues related to the computer model used to allocate costs to trading transactions, PSCo’s ability to track transactions individually, instead of in aggregate, for each hour and the allocation of system costs. The staff requested additional reporting through 2006.
PSCo, the staff of the CPUC and the OCC reached full settlement of the disputed issues on Sept. 10, 2004. The CPUC approved the settlement on Oct. 5, 2004. The settlement modifies the rules governing trading transactions to provide more specificity as to transaction priorities, record retention and cost assignment. The CPUC acknowledged the benefit of commodity trading. Consequently, the settlement provides for continuation of electric commodity trading as currently conducted by PSCo, and permits PSCo to begin trading natural gas as a risk mitigation measure in support of its electric trading. PSCo anticipates commencing natural gas trading activities as permitted by the settlement in the first half of 2005. The settlement also provides for the margin sharing mechanisms that are currently in place in the PSCo retail rates to continue through 2006. Finally, the settlement requires the cooperative development of auditing processes to provide the staff of the CPUC with information regarding PSCo’s trading operations and for the filing of monthly reports with respect to these trading operations. This proceeding is now complete.
Capacity and Demand
Assuming normal weather during 2005, system peak demand for the PSCo’s electric utility for each of the last three years and the forecast for 2005 is listed below.
The peak demand for PSCo’s system typically occurs in the summer. The 2004 system peak demand for PSCo occurred on July 13, 2004.
Energy Sources and Related Transmission Initiatives
PSCo expects to meet its net dependable system capacity requirements through existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options and phased expansion of existing generation at select power plants.
Purchased Power - PSCo has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, 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 firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide each utility’s reserve obligation, 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 2005 and generate the remainder with PSCo-owned resources. Approximately 47 percent of PSCo’s total system electric generation
capacity for 2005 will be provided by purchased power.
On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCRP) with the CPUC. PSCo had identified that it needs to provide for 3,600 MW of capacity through 2013 to meet load growth and replace expiring contracts. Of the amount needed, PSCo believes 2,000 MW will come from new resources, and 1,600 MW will come from entering into new contracts with existing suppliers whose contracts expire during the resource acquisition period.
On Dec. 17, 2004, the CPUC approved a settlement agreement between PSCo and many intervening parties concerning the LCRP. PSCo received the formal written decision of the CPUC in January 2005. The CPUC approved PSCo’s plan to construct a 750-MW pulverized coal-fired unit at the Comanche Station located near Pueblo, Colo. and transfer up to 250 MW of capacity ownership from the 750-MW unit to Intermountain Rural Electric Association and Holy Cross Energy, if negotiations with those entities are successful. The settlement agreement also enables PSCo to acquire resources through an all-source competitive bidding process.
Among other things, the approved settlement allows for additional emission controls to be installed and associated costs to be collected from customers at Comanche Station’s two existing coal-fired units. The settlement contains a confidential construction cost cap for the construction of the 750-MW Comanche 3 unit. It also includes a regulatory plan that authorizes PSCo to increase the equity component of its capital structure to 56 percent in its 2006 rate case to offset the debt equivalent value of PSCo’s existing purchased power agreements and to otherwise improve PSCo’s financial strength. Depending upon PSCo’s senior unsecured debt rating during the time of PSCo general rates cases, the approved settlement permits PSCo to include various amounts of construction work in progress in rate base without an allowance for funds used during construction offset associated with the Comanche 3 generating unit, additional emission controls on the Comanche 1 and 2 generating units and associated transmission. PSCo agreed to invest in additional demand-side management, accelerate the completion of an ongoing wind-saturation study and fund environmental programs in Pueblo, Colo.
In a separate docket, the CPUC granted PSCo’s request for approval of a 500-MW renewable energy solicitation. PSCo issued a request for proposal, with bids to be submitted in November 2004. PSCo is currently negotiating contracts with bidders of approximately 328 MW of renewable energy.
Purchased Transmission Services - PSCo has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.
Fuel Sources - PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2004, PSCo’s coal requirements for existing plants were approximately 9.8 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2004 were approximately 41 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.
PSCo operates the Hayden generating plant in Colorado. All of Hayden’s coal requirements are supplied under a long-term agreement. The Hayden facility is located in close proximity to a coal mine, which has historically provided the coal to fulfill Hayden’s fuel requirements under the long-term agreement. The mine operator has announced that the mine will close near the end of
2005. PSCo is currently investigating a number of alternatives to provide for an uninterrupted, economical fuel supply to the facility. It is anticipated that total fuel costs will increase following the closure of the mine, however, the amount of increased costs, if any, cannot be determined at this time. In addition to Hayden, PSCo has partial ownership in the Craig generating plant in Colorado. Approximately 70 percent of PSCo’s coal requirements for Craig are supplied by two long-term agreements.
PSCo has contracted for coal suppliers to supply approximately 98 percent of the Cherokee, Cameo, Valmont and remaining Craig stations’ projected requirements in 2005.
PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 94 percent of Arapahoe station’s projected requirements for 2005. Any remaining Arapahoe station requirements will be procured via spot market purchases.
PSCo has a number of coal transportation contracts, which expire over the course of 2005. PSCo is currently in the process of negotiating new transportation agreements. The ability to negotiate for coal transportation is not anticipated to impede the operation of PSCo’s coal-based generation facilities. However, it is expected that coal transportation costs will increase. Currently, the impact or extent of the increase cannot be determined.
PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.
Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of PSCo. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. PSCo also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices. See additional discussion under Item 7A - Quantitative and Qualitative Disclosures About Market Risk.
SPS
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - The PUCT has jurisdiction over SPS’ Texas operations as an electric utility and over its retail rates and services. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The NMPRC has jurisdiction over the issuance of securities. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation Commission have jurisdiction with respect to retail rates and services and construction of transmission or generation in their respective states. 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.
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. In July 2003, a unanimous settlement was reached providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis. As a result, 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, as allowed by the PUCT, if this condition is expected to continue.
PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of such fuel and purchased energy, fuel acquisition and management policies and purchase energy commitments. Under the PUCT’s regulations, 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.
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 beginning with the February 2002 billing cycle. In accordance with the NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005 for the period from October 2001 through April 2005.
SPS recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause 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, telephone response and abandoned call performance targets. If these targets are not met, SPS is required to make refunds to its customers of up to $950,000 per year. As of Dec. 31, 2004, SPS accrued $800,000 to reflect the expected refund obligation for those measures.
Pending and Recently Concluded Regulatory Proceedings - FERC
PSCo and SPS FERC Transmission Rate Case - On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint OATT. PSCo and SPS are seeking an increase in annual transmission service and ancillary services revenues of $6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, of which $1.7 million is attributable to SPS. In December 2004, the FERC suspended the filing and delayed the effective date of the proposed increase to May 20, 2005. The FERC also initiated a complaint proceeding against SPS, which would allow the FERC to order reductions below SPS’ currently effective rates. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The case has been set for hearing and settlement procedures.
SPS Wholesale Rate Complaint - In November 2004, several wholesale cooperative customers of SPS filed a $3 million rate complaint at the FERC requesting that the FERC investigate SPS’ wholesale power base rates and fuel clause calculations. In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund, effective Jan. 1, 2005. Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause. The FERC set the proposed rate changes into effect on Jan. 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding. The FERC set the consolidated proceeding for hearing and settlement judge procedures.
Southwest Power Pool (SPP) Restructuring - SPS is a member of the SPP regional reliability council, and SPP acts as transmission tariff administrator for the SPS system. In October 2003, SPP filed for FERC authorization to transform its operation into an RTO under FERC Order No. 2000. In addition, SPP made unilateral changes to the existing SPP membership agreement, which increases the current costs of SPS membership in SPP by approximately $1.5 million per year, in order to fund the start of RTO operations. On Feb. 10, 2004, the FERC conditionally approved SPP’s proposed formation as an RTO, subject to SPP meeting certain requirements. On Oct. 1, 2004, the FERC issued a further order granting the SPP status as an RTO. SPP is expected to commence RTO operations on Oct. 1, 2005. SPS is required to obtain NMPRC approval before it can transfer functional control of its electrical transmission system. When SPP begins RTO operations and SPS obtains all required approvals, SPS will be required to transfer functional control of its electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff.
Pending and Recently Concluded Regulatory Proceedings - PUCT
Texas Retail Fuel Cost - Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed with the PUCT its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003. SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period. Intervenor and PUCT staff testimony was filed in October 2004 and hearings were held in December 2004. Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to wholesale sales, among other things. Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors. SPS has recorded its best estimate of any potential liability related to the impact of this proceeding. In January 2005, SPS filed its post-hearing briefs disputing the intervenor objections. Reply briefs were
filed on Feb. 15, 2005, the administrative law judge is expected to issue his recommended proposal for decision by the end of April 2005, and PUCT action is expected by the end of May 2005. SPS is pursuing a settlement agreement with the parties involved.
In November 2003, SPS submitted a fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under-recoveries accrued during June through September 2003. In February 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge, which was approved by the PUCT in March 2004, went into effect May 2004 and will continue for 12 months.
In May 2004, SPS filed another fuel cost surcharge factor application in Texas to recover an additional $32 million of fuel cost recoveries accrued during January through March 2004. In June 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect the $32 million fuel cost under-recoveries surcharge factors for a 12-month period beginning November 2004. The PUCT approved the settlement in September 2004.
On Nov. 5, 2004, SPS submitted another fuel cost surcharge application with the PUCT for $30 million of fuel cost under-recoveries accrued from April 2004 through September 2004. These under-recoveries under the Texas retail fixed fuel collection process are primarily the result of higher than expected natural gas prices. SPS is also proposing in its November 2004 filing to increase its semi-annual fuel factors to take into account the increased cost of natural gas at its gas-fueled power plants. In January 2005, parties to the application reached a settlement agreement allowing SPS to collect the $30 million fuel cost under-recoveries through a surcharge during the 12-month period beginning May 2005. The PUCT is expected to approve the settlement in March 2005.
Lamb County Electric Cooperative - On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly-certificated area. The PUCT denied LCEC’s petition. See further discussion under Item 3 - Legal Proceedings.
Capacity and Demand
Assuming normal weather during 2005, system peak demand for the SPS’ electric utility for each of the last three years and the forecast for 2005 is listed below.
The peak demand for the SPS system typically occurs in the summer. The 2004 system peak demand for SPS occurred on Aug. 4, 2004.
Energy Sources and Related Transmission Initiatives
SPS expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers and demand-side management options to meet its net dependable system capacity requirements:
Purchased Power - SPS has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, 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 firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide each utility’s reserve obligation, 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.
Purchased Transmission Services - SPS has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one
year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.
*The lower 2003 SPS coal costs reflect a prior period fuel credit adjustment. The normalized cost per MMBtu was approximately $1.14.
Fuel Sources - SPS purchases all of its coal requirements for Harrington and Tolk electric generating stations from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to the plant bunkers. TUCO, in turn, arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to the plant bunkers to meet SPS’s requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires Dec. 31, 2016. For the Tolk station, the coal supply contract with TUCO expires Dec. 31, 2017. At Dec. 31, 2004, coal supplies at the Harrington and Tolk sites were approximately 25 and 24 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected 2005 requirements for Harrington and Tolk stations. TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Harrington and Tolk stations.
SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas suppliers for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.
Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of SPS. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. SPS also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices. See additional discussion under Item 7A - Quantitative and Qualitative Disclosures About Market Risk.
Xcel Energy Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Natural Gas Utility Trends
Changes in regulatory policies and market forces have shifted the industry from traditional bundled natural gas sales service to an unbundled transportation and market-based commodity service at the wholesale level and for larger commercial and industrial retail customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail LDC transportation service.
The natural gas delivery/transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local natural gas utility through the construction of interconnections directly with, and the purchase of natural gas from, interstate pipelines, thereby avoiding the delivery charges added by the local natural gas utility.
As LDCs, NSP-Minnesota, NSP-Wisconsin and PSCo provide unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to make them economically indifferent to whether natural gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs distribution system.
The most significant recent developments in the natural gas operations of the Utility Subsidiaries are the substantial and continuing increases 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 1994 to 2004, average annual sales to the typical residential customer declined from 108 Dth per year to 89 Dth per year on a weather-normalized basis. Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.
NSP-Minnesota
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of 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 gas supply plans for meeting customers’ future energy needs.
Purchased Gas and Conservation Cost Recovery Mechanisms - NSP-Minnesota’s retail natural gas rate schedules 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 has the authority to disallow recovery of certain costs if it finds 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.
Pending and Recently Concluded Regulatory Proceedings
NSP-Minnesota Retail Gas Rate Case - On Sept. 17, 2004, NSP-Minnesota submitted a $10 million natural gas general rate increase request to the MPUC with a requested ROE of 11.5 percent. An interim rate increase, subject to refund, of approximately $6.4 million was implemented effective Dec. 1, 2004. The administrative law judge held a pre-hearing conference and established a procedural schedule, with an MPUC decision expected in mid-2005. The Department of Commerce filed testimony in February 2005 recommending an increase of $1 million. NSP-Minnesota plans to file its rebuttal testimony on March 15, 2005.
North Dakota Retail Gas Rate Case - On Nov. 2, 2004, NSP-Minnesota submitted a natural gas general rate increase application to the NDPSC. The filing proposes an overall increase in annual revenues of $1.3 million, exclusive of natural gas supply costs, or 1.8
percent. On Dec. 1, 2004, the NDPSC issued an order approving a $0.7 million interim rate increase, or 1.1 percent, effective Jan. 1, 2005. The NDPSC staff is scheduled to file its testimony in March 2005, and the NDPSC will conduct evidentiary hearings in April 2005. The NDPSC is required to issue its order by June 2, 2005. On Feb. 17, 2005, NSP-Minnesota and the NDPSC staff filed a settlement agreement with the NDPSC. Under the terms of the settlement, the NDPSC can elect one of two alternatives. The alternatives are a $745,000 rate increase and a $15.70 monthly residential service charge or an $887,000 rate increase with an $8.75 monthly residential service charge. The NDPSC is expected to consider the settlement agreement at a hearing in March 2005.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 647,547 MMBtu for 2004, which occurred on Jan. 29, 2004.
NSP-Minnesota purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 506,391 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 16 percent of winter natural gas requirements and 19 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 34 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. NSP-Minnesota’s 2003-2004 entitlement levels were approved on Sep. 2, 2004, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. The 2004-2005 entitlement levels are pending MPUC action.
Natural Gas Supply and Costs
NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.
The following table summarizes the average 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 various cost recovery adjustment mechanisms.
NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2005 through 2017.
NSP-Minnesota has certain natural gas supply and transportation 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, 2004, NSP-Minnesota was committed to approximately $1.09 billion in such obligations under these contracts.
NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 35 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.
NSP-Wisconsin
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - NSP-Wisconsin is subject to retail rate and other regulation by the PSCW and the MPSC. In addition, each of the state commissions certifies the need for new retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.
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 gas 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 gas rate schedules for Michigan customers include a gas cost recovery factor which is based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 153,423 MMBtu for 2004, which occurred on Jan. 29, 2004.
NSP-Wisconsin purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 124,492 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 23 percent of winter natural gas requirements and 29 percent of peak day, firm requirements of NSP-Wisconsin.
NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 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 2004-2005 supply plan was approved by the PSCW in October 2004.
Natural Gas Supply and Costs
NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.
The following table summarizes the average 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 2005 through 2013.
NSP-Wisconsin has certain natural gas supply and transportation 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, 2004, NSP-Wisconsin was committed to approximately $129 million in such obligations under these contracts.
NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 35 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.
PSCo
Ratemaking Principles
Summary of Regulatory Agencies and Areas of Jurisdiction - PSCo is subject to the jurisdiction of 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 a GCA mechanism, which allows PSCo to recover its actual costs of purchased gas. Effective Nov. 1, 2004, the GCA is revised monthly to allow for changes in gas rates. Previously, the GCA rate was revised at least annually to coincide with changes in purchased gas 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.
Capability and Demand
PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,781,088 MMBtu. In addition, firm transportation customers hold 477,419 MMBtu for PSCo of capacity without supply backup. Total firm delivery obligation for PSCo is 2,258,507 MMBtu per day. The maximum daily deliveries for PSCo in 2004 for firm and interruptible services were 1,860,958 MMBtu on Jan. 5, 2004.
PSCo purchases natural gas from independent suppliers. The natural gas supplies are delivered to the respective delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to each company. These agreements provide for firm deliverable pipeline capacity of approximately 1,792,543 MMBtu/day, which includes 826,866 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 40,000 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 the companies’ city gate meter stations and a small amount is received directly from wellhead sources.
PSCo has received approval and is in the process of closing the Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity. See further discussion at Note 16 to the Consolidated Financial Statements.
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.
Natural Gas Supply and Costs
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous supply sources with varied contract lengths.
The following table summarizes the average cost per MMBtu of natural gas purchased for resale by PSCo’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.
PSCo has certain natural gas supply and transportation 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, 2004, PSCo was committed to approximately $1.5 billion in such obligations under these contracts, which expire in various years from 2005 through 2025.
PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. PSCo also utilizes a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market-sensitive, price to its customers. During 2004, PSCo purchased natural gas from approximately 37 suppliers.
Xcel Energy Gas Operating Statistics
NONREGULATED SUBSIDIARIES
Through non-utility subsidiaries, Xcel Energy invested in and operated several nonregulated businesses in a variety of industries. At Dec. 31, 2004, Xcel Energy has divested its ownership interest in all significant non-utility subsidiaries. The following is an overview of nonregulated businesses, which are reported as components of continuing operations.
Utility Engineering Corp. (UE)
UE was incorporated in 1985 under the laws of Texas. UE is engaged in engineering, design, construction management and other miscellaneous services. UE currently has five wholly owned subsidiaries, including Universal Utility Services LLC, Precision Resource Co., Quixx Corp., Proto-Power Corp. and Applied Power Associates Inc.
On March 2, 2005, Xcel Energy agreed to sell its non-regulated subsidiary UE to Zachry Group, Inc. Zachry agreed to acquire all of the outstanding shares of UE, including three UE subsidiaries: Precision Resource Co., a professional staffing company; Proto-Power Corp., an engineering and project management company dedicated to the nuclear power industry; and Universal Utility Services, LLC, a full-service industrial maintenance group. Quixx Corp., a subsidiary of UE that partners in cogeneration projects is not included in the transaction. Xcel Energy expects to record a small loss as a result of the transaction; however, the transaction is not expected to have a material effect on the financial condition of Xcel Energy. The transaction is subject to customary terms and conditions as to closing and is expected to be completed in April 2005.
Eloigne Company (Eloigne)
Eloigne was established in 1993 and its principal business is the acquisition of rental housing projects that qualify for low-income housing tax credits under current federal tax law and Colorado state tax law. As of Dec. 31, 2004, Eloigne consolidated $147 million of affordable housing property, including $126 million of limited partnership-owned property, pursuant to FASB Interpretation No. 46. Eloigne also had approximately $7 million in equity interests in jointly owned projects. Completed Eloigne projects as of Dec. 31, 2004, are expected to generate tax credits of $38 million over the time period of 2005 through 2012.
ENVIRONMENTAL MATTERS
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 at this time 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, generally, what effect future laws or regulations may have upon Xcel Energy’s operations. For more information on environmental contingencies, see Notes 16 and 17 to the Consolidated Financial Statements, environmental matters in Management’s Discussion and Analysis under Item 7 and the matter discussed below.
NSP-Minnesota Notice of Violation - On Dec. 10, 2001, the Minnesota Pollution Control Agency (MPCA) issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. On April 22, 2004, the MPCA executed an agreement with NSP-Minnesota to resolve the alleged air quality violations at the A.S. King generating plant and address alleged air quality reporting violations at the Red Wing and Wilmarth generating plants. Conditions of the agreement were for NSP-Minnesota to pay an $80,000 civil penalty and to complete corrective actions at the A.S. King, Red Wing and Wilmarth generating plants. In 2004, NSP-Minnesota paid the civil penalty and completed all required corrective actions. On Dec. 15, 2004, the MPCA issued a letter acknowledging receipt of the civil penalty payment and completion of all requirements in the agreement.
CAPITAL SPENDING AND FINANCING
For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.
EMPLOYEES
The number of full-time Xcel Energy employees in continuing operations at Dec. 31, 2004, is presented in the table below. Of the full-time employees listed below, 5,541 or 52 percent, are covered under collective bargaining agreements.
* NSP-Minnesota full-time employees include 395 employees loaned to the NMC. In addition, the NMC has 778 full-time employees of its own.
EXECUTIVE OFFICERS
Wayne H. Brunetti, 62, Chairman of the Board, August 2001 to present; Chief Executive Officer, August 2000 to present; Director of PSCo, June 1994 to present; Chairman of PSCo, February 2000 to present. Previously, President, Xcel Energy, August 2000 to October 2003; Vice Chairman, President, Chief Operating Officer and Director of New Century Energies, Inc. (NCE), 1997 to August 2000.
Paul J. Bonavia, 53, President - Commercial Enterprises, December 2003 to present. Previously, President - Energy Markets, Xcel Energy, August 2000 to December 2003; Senior Vice President and General Counsel of NCE, 1997 to August 2000.
Benjamin G.S. Fowke III, 46, Chief Financial Officer, Xcel Energy, October 2003 to present; Vice President, Xcel Energy, November 2002 to present. Previously, Treasurer, Xcel Energy from November 2002 to May 2004, Vice President and Chief Financial Officer - Energy Markets, Xcel Energy from August 2000 to November 2002, Vice President - Retail Services and Energy Markets, NCE from January 1999 to July 2000 and Vice President - Finance/Accounting, e prime from May 1997 to December 1998.
Raymond E. Gogel, 54, Vice President and Chief Information Officer, Xcel Energy, April 2002 to present. Previously, Vice President and Senior Client Services Principal for IBM Global Services from April 2001 to April 2002 and Senior Project Executive for IBM Global Services from April 1999 to April 2001.
Cathy J. Hart, 55, Vice President and Corporate Secretary, Xcel Energy, August 2000 to present. Previously, Secretary of NCE from 1998 to August 2000.
Gary R. Johnson, 58, Vice President and General Counsel, Xcel Energy, August 2000 to present. Previously, Vice President and General Counsel of NSP from 1991 to August 2000.
Richard C. Kelly, 58, President and Chief Operating Officer, Xcel Energy, October 2003 to present. Previously, Vice President and Chief Financial Officer, Xcel Energy, August 2002 to October 2003, President - Enterprises, Xcel Energy, August 2000 to August 2002, Executive Vice President and Chief Financial Officer for NCE from 1997 to August 2000 and Senior Vice President of PSCo from 1990 to 1997.
Cynthia L. Lesher, 56, Chief Administrative Officer, Xcel Energy, August 2000 to present and Chief Human Resources Officer, Xcel Energy, July 2001 to present. Previously, President of NSP-Gas from July 1997 to August 2000 and prior was Vice President-Human Resources of NSP.
Teresa S. Madden, 48, Vice President and Controller, Xcel Energy, January 2004 to present. Previously, Vice President of Finance for Xcel Energy Customer and Field Operations from August 2003 to January 2004, Interim CFO for Rogue Wave Software, Inc. from February 2003 to July 2003, Corporate Controller for Rogue Wave Software, Inc. from October 2000 to February 2003, Controller for NCE, 1997 to September 2000.
George E. Tyson II, 39, Vice President and Treasurer, Xcel Energy, May 2004 to present. Previously, Managing Director and Assistant Treasurer, Xcel Energy from July 2003 to May 2004; Director of Origination - Energy Markets, Xcel Energy from May 2002 to July 2003; Associate and Vice President, Deutsche Bank Securities from December 1996 to April 2002.
Patricia K. Vincent, 46, President - Customer and Field Operations, Xcel Energy, July 2003 to present. Previously, President - Retail, Xcel Energy, March 2001 to July 2003, Vice President of Marketing and Sales of Xcel Energy from August 2000 to March 2001, Vice President of Marketing and Sales of NCE from January 1999 to August 2000.
David M. Wilks, 58, President - Energy Supply, Xcel Energy, August 2000 to present. Previously, Executive Vice President and Director of PSCo and New Century Services from 1997 to August 2000 and President, Chief Operating Officer and Director of SPS from 1995 to August 2000.
Item 2
Item 2 - Properties
Virtually all of the utility plant of NSP-Minnesota, NSP-Wisconsin and PSCo is subject to the lien of their first mortgage bond indentures.
Electric utility generating stations:
NSP-Minnesota
(a) Based on NSP-Minnesota’s ownership interest of 59 percent.
NSP-Wisconsin
* RDF is refuse-derived fuel, made from municipal solid waste.
PSCo
(a) Based on PSCo’s ownership interest of 9.7 percent.
(b) Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.
SPS
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2004:
Electric utility transmission and distribution substations at Dec. 31, 2004:
Gas utility mains at Dec. 31, 2004:
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against Xcel Energy in addition to the regulatory matters discussed in Item 1. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.
Legal Contingencies
Nuclear Waste Disposal Litigation - The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear substance 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 substances at a permanent storage or disposal facility. The federal government has designated the site as Yucca Mountain in Nevada. This designation has resulted in extensive litigation.
On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE’s partial breach of contract. NSP-Minnesota has demanded damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island and Monticello nuclear generating plants, costs related to the Private Fuel Storage, LLC and costs relating to the 1994 and 2003 state legislation relating to the storage of spent nuclear fuel at Prairie Island. On July 31, 2001, the Court of Federal Claims granted NSP-Minnesota’s motion for partial summary judgment on liability. The Court of Federal Claims has directed the parties to be prepared for trial on this matter by Nov. 1, 2005.
On July 9, 2004, the federal Court of Appeals for the District of Columbia issued a decision to consolidate cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to the majority of the licensing regulations of the NRC, the congressional resolution selecting Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the selection of Yucca Mountain. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountain licensing. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel.
Lamb County Electric Cooperative (SPS)- On July 24, 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas, which appeal is currently pending. Briefs have been filed with the Court of Appeals and oral arguments are scheduled for March 23, 2005.
On Oct. 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers. The PUCT order of May 23, 2003, found that SPS was legally serving the disputed customers, thus collaterally determining the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.
Manufactured Gas Plant Insurance Coverage Litigation (NSP-Wisconsin) - In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against
NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Wisconsin court denied the insurers’ motion to stay the Wisconsin case pending resolution of the Minnesota action. On Jan. 6, 2005, the Minnesota court issued an injunction prohibiting NSP-Wisconsin from prosecuting the Wisconsin action. No trial date has been set in either proceeding. The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits should not have an impact on shareholders, and no accruals have been made.
Additional Information
For more discussion of legal claims and environmental proceedings, see Note 16 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, and Management’s Discussion and Analysis under Item 7, incorporated by reference.
Item 4
Item 4 - Submission of Matters to a Vote of Security Holders
No issues were submitted for a vote during the fourth quarter of 2004.
PART II
Item 5
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Quarterly Stock Data
Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE), the Chicago Stock Exchange and the Pacific Stock Exchange. 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 2004 and 2003 and the dividends declared per share during those quarters.
Book value per share at Dec. 31, 2004, was $12.99. The number of common shareholders of record as of Dec. 31, 2004 was 116,358.
Xcel Energy’s Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2004 and 2003, 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.
See Item 12 for information concerning securities authorized for issuance under equity compensation plans.
Item 6
Item 6 - Selected Financial Data
(a) Operating revenues and expenses for 2000 through 2002 include reclassifications to conform to the 2003 and 2004 presentation. These reclassifications related to reporting electric and natural gas trading revenues and costs on a net basis, and to presenting the results of discontinued operations separately. These reclassifications had no effect on net income.
(b) Dividends in 2000 reflect dividends paid by predecessor companies before, and Xcel Energy after, the Xcel Energy merger in August 2000.
(c) Excludes undistributed equity income and includes allowance for funds used during construction.
(d) Total assets for 2004, 2003 and 2002 reflect the classification of accrued future plant removal costs as a component of regulatory liabilities. For periods prior to 2001, they are reflected as a component of accumulated depreciation. Accrued future removal costs were $891 million, $852 million and $800 million in 2004, 2003 and 2002, respectively.
(e) Long term debt includes only debt of continuing operations.
(f) The 2002 average number of common and potentially dilutive shares has been restated to include the effect of dilutive securities, which were excluded in 2002 due to Xcel Energy’s loss from continuing operations. Including these securities would have been antidilutive, or would have reduced the reported loss per share. In 2002, the loss from continuing operations that was caused by NRG made some securities “antidilutive” or would have reduced the reported loss per share. In 2003, NRG’s results were reclassified to discontinued operations.
Item 7
Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
BUSINESS SEGMENTS AND ORGANIZATIONAL OVERVIEW
Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). In 2004, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo) and Southwestern Public Service Co. (SPS). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. Discontinued utility operations include the activity of Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company that was sold in January 2003; Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne Light, Fuel and Power Co. (Cheyenne), a regulated electric and natural gas utility that was sold in January 2005.
Xcel Energy’s nonregulated subsidiaries in continuing operations include Utility Engineering Corp. (engineering, construction and design) and Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits). During 2003, Planergy International, Inc. (energy management solutions) closed and began selling a majority of its business operations with final dissolution occurring in 2004. On March 2, 2005, Xcel Energy agreed to sell its non-regulated subsidiary UE to Zachry Group, Inc. Zachry agreed to acquire all of the outstanding shares of UE, including three UE subsidiaries: Precision Resource Co., a professional staffing company; Proto-Power Corp., an engineering and project management company dedicated to the nuclear power industry; and Universal Utility Services, LLC, a full-service industrial maintenance group. Quixx Corp., a subsidiary of UE that partners in cogeneration projects is not included in the transaction. Xcel Energy expects to record a small loss as a result of the transaction; however, the transaction is not expected to have a material effect on the financial condition of Xcel Energy. The transaction is subject to customary terms and conditions as to closing and is expected to be completed in April 2005.
During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc. (Seren), a broadband communications services company. During 2003, Xcel Energy also divested its ownership interest in NRG Energy, Inc. (NRG), an independent power producer. On May 14, 2003, NRG filed for bankruptcy to restructure its debt. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. During 2003, the board of directors of Xcel Energy also approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (Xcel Energy International), an international independent power producer, operating primarily in Argentina and e prime inc. (e prime), a natural gas marketing and trading company. NRG, Xcel Energy International, e prime and Seren are presented as a component of discontinued operations.
See Note 3 to the Consolidated Financial Statements for further discussion of discontinued operations.
FORWARD-LOOKING STATEMENTS
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; risks associated with the California power market; 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 Securities and Exchange Commission (SEC), including Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004.
MANAGEMENT’S STRATEGIC PLAN
The structure of the utility industry is continually changing, which is driven, in part, by the many different types of government regulation over the industry. Generally, the states in which a utility operates determine the rates that the utility charges its retail customers. The Federal Energy Regulatory Commission (FERC) establishes the rates that utilities charge for power sold at the
wholesale level. The FERC also develops and administers various rules that govern how utilities operate. Utilities also face a wide range of environmental regulations from various government agencies, at both the state and federal level.
The mix of state and federal regulations result in numerous rules and regulations, which are not always consistent and are subject to continual change. Clearly, compliance with all of the regulatory requirements increases the complexity and uncertainty of our business.
In the last decade or so, the FERC and many states developed rules to encourage competition and deregulation of the utility sector. As a result of these regulatory changes, many utilities have taken steps to prepare for competition and the changing rules. These actions included:
• completion of mergers and acquisitions to increase economies of scale;
• efficiency improvements and cost cutting to avoid rate cases and improve competitive position;
• sales of power plants;
• use of purchase power contracts to meet growth in electric requirements; and
• development of nonregulated ventures.
On the federal level, the FERC is still very active in promoting wholesale competition. Wholesale operations account for approximately 16 percent of our revenue. FERC has authority to withhold market-based rates on wholesale sales in certain areas where a utility is determined to have “market power control.” However, Xcel Energy believes that it will continue to have the ability to make sales under its market-based tariff.
As part of its agenda to encourage competition, the FERC has also been very active in promoting regional transmission organizations (RTOs). In the past, each individual utility controlled its transmission lines. Based on certain FERC initiatives, RTOs will control the operations of transmission lines for an entire region to ensure that all parties that want to sell power have access to the lines. We currently participate in the Midwest Independent Transmission System Operator, Inc. (MISO) and the Southwest Power Pool (SPP). We are supportive of RTO participation, provided that they offer benefits to our customers and we have clear cost-recovery mechanisms. In 2005, the MISO will begin its Day 2 operations. This will result in uncertainty, which may have a positive or negative impact on our wholesale margins.
However, at the state level, many states have stopped utility restructuring activity due to the failure of the California power markets, the collapse of the independent power producers and other factors.
For Xcel Energy, no significant retail regulatory restructuring has occurred or is expected to occur in any of the states in which we have major utility operations. In some parts of Texas, retail customers can choose their energy provider. However, due to legislation that extends through 2007, the panhandle of Texas, where we have utility operations, remains under traditional regulation. We believe that the panhandle will remain under traditional regulation after 2007.
Our retail operations represent approximately 82 percent of our revenues. Retail rates are set by state commissions and are intended to provide the utility the opportunity to earn an authorized return on equity. Whether the utility actually earns its authorized return on equity is dependent on many factors including the level of sales growth, changes in a company’s cost structure, capital investment, interest rates and other items.
Until recently, we have avoided the need to file rate cases by experiencing relatively robust growth in our service territories as well as aggressively managing the costs of our business. Through two mergers, we have realized cost savings and operational efficiencies. These steps have helped us to avoid filing rate cases, but at the same time, we have made significant investments. While we will continue to look for ways to reduce costs, the opportunities are no longer large enough to further delay rate cases.
Our regulatory strategy is to ensure that we have the opportunity to earn our authorized return on equity in each state. We are currently not earning our authorized return on equity in the majority of the states where we have our regulated utility operations. As a result, we have or in the near-term will begin filing general rate increases in the majority of our jurisdictions as follows.
• In September 2004, we filed for an approximately $10 million natural gas rate increase in Minnesota. The request assumes an 11.5 percent return on equity. Interim rates, subject to refund, went into effect in December 2004 and we expect a decision this summer.
• Also in 2004, we filed for a $5 million transmission increase at FERC.
• In Wisconsin, we are required to file a rate case every other year. Therefore, NSP-Wisconsin will file a case during 2005.
• In Minnesota, we plan to file an electric rate case in the fourth quarter of this year with interim rates, subject to refund, effective in early 2006. We expect a final commission decision in late summer or early fall of 2006.
• Finally, we intend to file an electric rate case in Colorado in 2006, with rates expected to be in effect during 2007.
While recovery of costs cannot be assured, we are optimistic we will receive fair treatment. We believe that we have fair regulation as demonstrated by the successful agreement reached on projects like the metropolitan emissions reduction project (MERP) in Minnesota and the new construction of the Comanche 3 electric generating unit in Colorado. Our ability to maintain a constructive regulatory framework is a critical component of our strategy and ultimate success.
Though we remain open to all opportunities to increase shareholder value, our strategy is to invest in our core electric and natural gas businesses to meet the growing energy needs of our customers, while earning a fair return on our investments. We refer to our strategy as Building the Core. We have no plans or interest in deviating from our core business.
We see four critical factors to create incremental value for our shareholders and view these factors as building blocks. They are largely independent of each other, but taken together, they have the potential to create significant additional value.
• The first is service territory growth. With the strength and diversity of our service territory, growth provides a solid foundation year after year.
• The second driver is incremental investment in our core businesses. Certain incremental investment has already started at a modest level and will grow quickly in the coming years. Key projects include the MERP project and the Comanche 3 coal plant.
• The third driver is to increase the level of equity that we have invested in our operating companies. Additional equity will increase our financial strength, support a higher credit rating and add to earnings and cash flow. We will work with our regulators to gain support for this initiative.
• Lastly, we will strive to earn our regulated, authorized returns, which will require filing for rate increases in our largest jurisdictions over the next few years.
Execution of our strategy will allow us to meet or exceed our financial objective of delivering an average total return of 7 percent to 9 percent per year. Our total return objective is based on our expectations of long-term earnings growth of 2 percent to 4 percent and a dividend yield of approximately 5 percent.
We have established a dividend policy that we believe is sustainable and contributes to a competitive total return for our shareholders. Our objective is to deliver the financial results that will enable our board of directors to grant annual dividend increases at a rate consistent with our long-term earnings growth rate.
As we look to 2005, we are focused on several challenges, in addition to the normal day-to-day operations of our utility business.
• We must prepare for operational uncertainty surrounding the implementation of various FERC initiatives, which could impact our short-term wholesale margins.
• We must manage our procurement efforts to attempt to mitigate the impact of rising fuel costs, which are passed on to our customers.
• We must continue to look for creative ways to offset rising healthcare and benefit costs, while we continue our efforts to improve reliability and customer service.
• While we believe we are well positioned for changing environmental rules and regulations based on the work we have done in the last few years on projects such as MERP, we plan to continue our aggressive efforts to improve our environmental performance.
• We need to obtain uncontested environmental permits for the new construction of the Comanche 3 coal plant.
• We expect to complete the sale of Seren.
• Finally, we will need to seek a Minnesota electric rate increase at the end of 2005. This case will be important as we move into 2006.
We believe that we have a solid and straightforward strategy and that, as we execute our plan, it will serve to increase shareholder value.
FINANCIAL REVIEW
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying Consolidated Financial Statements and Notes. All note references refer to the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
Summary of Financial Results
The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting principles (GAAP). Continuing operations consist of the following:
• regulated utility subsidiaries, operating in the electric and natural gas segments; and
• several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.
Discontinued operations consist of the following:
• Seren, a nonregulated subsidiary, which was classified as held for sale in the third quarter of 2004 based on a decision to divest this investment;
• the regulated natural gas businesses Viking and BMG, which were sold in 2003;
• the regulated utility business of Cheyenne, which was sold in January 2005;
• NRG, which emerged from bankruptcy in late 2003, at which time Xcel Energy divested its ownership interest in NRG; and
• the nonregulated subsidiaries Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.
Prior-year financial statements have been restated to conform to the current-year presentation and classification of certain operations as discontinued. See Note 3 to the Consolidated Financial Statements for a further discussion of discontinued operations.
(a) Not a reportable segment. Included in All Other segment results in Note 19 to the Consolidated Financial Statements.
(b) Includes tax benefit related to NRG. See Note 3 to the Consolidated Financial Statements.
While earnings from continuing operations for 2004 were flat compared with 2003, the current period results were favorably impacted by electric sales growth, short-term wholesale markets and lower depreciation, offset by the negative impact of unfavorable weather, legal settlement costs and the impacts of certain regulatory accruals, compared with the same period in 2003.
The loss from discontinued operations in 2004 is largely due to an after-tax impairment charge of $143 million related to the planned sale of Seren. The after-tax impairment charge was increased in the fourth quarter of 2004 from the impairment estimate recorded in the third quarter of 2004 based on further developed market information, as well as preliminary feedback from prospective buyers. The earnings in 2003 from discontinued operations are primarily due to an adjustment to previously estimated tax benefits related to Xcel Energy’s write-off of its investment in NRG. NRG recorded more than $3 billion of asset impairment and other charges in 2002 as it commenced its financial restructuring. Results from discontinued operations are discussed in the Discontinued Operations section later.
Common Stock Dilution - Dilution, primarily from common stock and convertible securities issued in 2002, reduced the utility segment earnings from continuing operations by 12 cents per share for 2003, compared with average common stock and equivalent levels in 2002. Total earnings from continuing operations were reduced by 11 cents per share for 2003, compared with 2002 share levels. In 2004, 2003 and 2002, approximately 423.3 million, 418.9 million and 384.6 million average common shares and equivalents, respectively, were used in the calculation of diluted earnings per share.
Statement of Operations Analysis - Continuing Operations
The following discussion summarizes the items that affected the individual revenue and expense items reported in the Consolidated Statements of Operations.
Electric Utility, Short-Term Wholesale and Commodity Trading Margins
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric utility margin.
Xcel Energy has two distinct forms of wholesale marketing activities: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from Xcel Energy’s generation assets and 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.
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Margins from commodity trading activity are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the FERC. On a consolidated basis, the impact of the JOA is eliminated. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of trading costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Commodity trading costs include fuel, purchased power, transmission and other related costs. The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:
The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years ended Dec. 31:
Base Electric Utility Revenue
2004 Comparison with 2003 - Base electric utility revenues increased due to weather-normalized retail sales growth of approximately 1.8 percent, higher fuel and purchased power costs, which are largely passed through to customers, and higher revenues from firm wholesale customers. Partially offsetting the higher revenues was the impact of significantly cooler summer temperatures in 2004 compared with the summer of 2003, as well as estimated customer refunds related to quality-of-service obligations in Colorado.
2003 Comparison with 2002 - Base electric utility revenues increased due to weather-normalized retail sales growth of approximately 1.5 percent, higher fuel and purchased power costs, which are largely passed through to customers, and higher capacity sales in Texas. In addition, the AQIR was implemented in Colorado in January 2003 for the recovery of investments and related costs to improve air quality. Partially offsetting the higher revenues was the impact of warmer temperatures during the summer of 2002 compared with the summer of 2003, as well as 2003 rate reductions related to lower property taxes in Minnesota and estimated customer refunds related to service quality requirements in Colorado.
Base Electric Utility Margin
2004 Comparison to 2003 - Base electric utility margin decreased due to the impact of weather, higher purchased capacity costs associated with new contracts to support growth, higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms, mainly in Wisconsin, and regulatory accruals associated with potential customer refunds related to service quality obligations in Colorado and fuel reconciliation proceedings in Texas. These decreases were partially offset by weather-normalized sales growth.
2003 Comparison to 2002 - Base electric utility margin decreased due mainly to higher purchased capacity costs associated with new contracts to support growth, the allowed recovery of fuel and purchased power costs in excess of actual costs in 2002 under the sharing provisions of the incentive cost adjustment mechanism in Colorado, compared with passing through costs with no sharing provisions under the interim adjustment clause in 2003, and the impact of weather. Also decreasing margin were 2003 rate reductions related to lower property taxes in Minnesota and estimated refunds to customers related to service quality requirements in Colorado. The decreases were partially offset by weather-normalized sales growth, the implementation of the AQIR and higher capacity sales, as previously discussed.
Short-Term Wholesale and Commodity Trading Margin
2004 Comparison to 2003 - Short-term wholesale and commodity trading margins increased approximately $33 million in 2004 compared with 2003. The increase reflects a number of market factors, including higher market prices, additional resources available for sale and a pre-existing contract, which provided approximately $17 million of short-term wholesale margins in 2004 and expired in the first quarter of 2004.
2003 Comparison to 2002 - Short-term wholesale and commodity trading margins increased approximately $43 million in 2003 compared with 2002. The increase reflects more favorable market conditions in the northern regions.
Natural Gas Utility Margins
The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin.
The following summarizes the components of the changes in natural gas revenue and margin for the years ended Dec. 31:
Natural Gas Revenue
2004 Comparison to 2003 - Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are passed through to customers. Retail natural gas weather-normalized sales declined in 2004, largely due to the rising cost of natural gas and its impact on customer usage.
2003 Comparison to 2002 - Natural gas revenue increased mainly due to higher natural gas costs in 2003, which are passed through to customers.
Natural Gas Margin
2004 Comparison to 2003 - Natural gas margin decreased due to a full year of the base rate decrease, which was effective July 1, 2003, agreed to in the settlement of the PSCo 2002 general rate case and the impact of warmer winter temperatures in 2004 compared with 2003. The rate case settlement agreement is discussed further under Factors Affecting Results of Continuing Operations.
2003 Comparison to 2002 - Natural gas margin decreased due to the rate decrease discussed above and the impact of warmer winter temperatures in 2003 compared with 2002. The rate case settlement agreement is discussed further under Factors Affecting Results of Continuing Operations.
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, which affects overall results. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of gas or electricity the average customer historically has used 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:
• weather in 2004 decreased earnings by an estimated 8 cents per share;
• weather in 2003 had minimal impact on earnings per share; and
• weather in 2002 increased earnings by an estimated 6 cents per share.
Nonregulated Operating Margins
The following table details the changes in nonregulated revenue and margin included in continuing operations:
2004 Comparison to 2003 - Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in an independent power producing entity that was no longer majority owned.
2003 Comparison to 2002 - Nonregulated revenue increased in 2003, due mainly to increased revenues at Utility Engineering. Nonregulated margin decreased in 2003, due to higher cost of goods sold at a subsidiary of Utility Engineering.
Non-Fuel Operating Expense and Other Items
Other Utility Operating and Maintenance Expense - Other operating and maintenance expenses for 2004 increased by approximately $22 million, or 1.4 percent, compared with 2003. Of the increase, $12 million of increased costs are offset by increased revenue, including those incurred to assist with the storm damage repair in Florida. The remaining increase of $10 million is primarily due to lower pension credits and higher employee benefit costs of $31 million, higher electric service reliability costs of $9 million, higher information technology costs of $8 million, higher legal settlement costs of $7 million, higher plant-related costs of $4 million, higher costs related to a customer billing system conversion of $4 million and $4 million of increased costs primarily related to compliance with the Sarbanes-Oxley Act of 2002. The higher costs were partially offset by lower compensation costs of $43 million, lower costs associated with inventory adjustments of $14 million and lower private fuel storage costs of $6 million.
Other operating and maintenance expenses increased $90 million, or 6.0 percent, in 2003 compared with 2002. The increase is due primarily to higher employee-related costs, including higher performance-based compensation of $36 million, restricted stock unit grants of $29 million, lower pension credits of $19 million and higher medical and health care costs of $9 million. In 2002, there were no restricted stock unit grants and only a partial award of performance-base compensation. In addition, other utility operating and maintenance expense for 2003 reflects inventory write-downs of $8 million, higher uncollectible accounts receivable of $3 million, higher reliability expenses of $6 million and a software project write-off of $2 million. The increase was partially offset by lower information technology costs resulting from centralization.
Other Nonregulated Operating and Maintenance Expense - Other nonregulated operating and maintenance expenses decreased $14 million, or 19.6 percent, in 2004 compared with 2003. This decrease resulted from the dissolution of Planergy and the discontinued consolidation of an investment in an independent power producing entity that was no longer majority owned after the divestiture of NRG. See additional discussion of the total results for each nonregulated subsidiary later.
Other nonregulated operating and maintenance expenses decreased $21 million, or 23.2 percent, in 2003 compared with 2002. The 2002 expenses included employee severance costs at the holding company. These expenses are included in the results for each nonregulated subsidiary, as discussed later.
Depreciation and Amortization - Depreciation and amortization expense for 2004 decreased by approximately $21 million, or 2.8 percent, compared with 2003, and $18 million, or 2.4 percent, in 2003 compared with 2002. The fluctuations are largely due to several regulatory decisions in 2003. In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million compared with 2003.
In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million. PSCo experienced the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003.
During 2003, the Minnesota Legislature authorized additional spent nuclear fuel storage at the Prairie Island nuclear plant. In December 2003, the MPUC extended the authorized depreciable lives of the two generating units at the Prairie Island nuclear plant, retroactive to Jan. 1, 2003, reducing depreciation by $22 million.
Special Charges - Special charges in 2004 were $17.6 million relating to the settlement of shareholder litigation. Special charges reported in 2003 relate to the TRANSLink Transmission Co., LLC (TRANSLink) project and NRG restructuring costs. Special charges for 2002 include NRG restructuring costs, as discussed later, but are largely related to regulated utility costs. Regulated utility earnings from continuing operations were reduced by approximately 2 cents per share in 2002 due to a $5 million regulatory recovery adjustment for SPS and $9 million in employee separation costs associated with a restaffing initiative for utility and service company operations. See Note 2 to the Consolidated Financial Statements for further discussion of these items.
Interest and Other Income, Net of Nonoperating Expenses - Interest and other income, net of nonoperating expenses increased $5 million in 2004 compared with 2003. The increase is due to interest income related to the finalization of prior-period Internal Revenue Service (IRS) audits of $10.5 million. Partially offsetting the increase was the impact of a Utility Engineering gain on the sale of water rights in 2003, net of write-offs of certain intangible assets.
Interest and other income, net of nonoperating expenses decreased $27 million in 2003 compared with 2002. Interest income decreased $13 million primarily due to interest received on tax refunds in 2002. Other income decreased $10 million primarily due to a gain on the sale of contracts at Planergy in 2002.
Interest and Financing Costs - Interest charges and financing costs decreased approximately $16 million, or 3.6 percent, for 2004, compared with 2003. The decrease for the year reflects savings from refinancing higher coupon debt during 2003 and lower credit line fees, partially offset by interest expense related to prior period IRS audits.
Interest and financing costs increased approximately $30 million, or 7.1 percent, for 2003 compared with 2002. This increase was due to the full-year impact of the issuance of long-term debt in the latter part of 2002 intended to reduce dependence on short-term debt. In addition, during 2002, Xcel Energy incurred approximately $15 million to redeem temporary holding company debt. During 2003, Xcel Energy issued approximately $1.7 billion of long-term debt to refinance higher coupon debt. During 2002, certain long-term debt was refinanced at higher interest rates.
Income Tax Expense - The effective tax rate was 23.2 percent for the year 2004, compared with 24.6 percent for the same period in 2003. Significant tax benefits were recorded during the fourth quarters of 2004 and 2003 due to the resolution of tax audit issues, largely related to prior periods.
Significant income tax audit activity occurring in 2003 continued in 2004. With the exception of the corporate-owned life insurance (COLI) loan interest deductibility, as discussed in Note 16, during 2004, Xcel Energy concluded IRS income tax audit and appeal activities spanning several examination cycles dating back to 1993. In addition, the IRS nearly completed the examination cycle ended 2001 and began its review of Xcel Energy’s 2002 and 2003 tax years.
In 2004, income tax benefits of $39.3 million were recorded, including $28.9 million related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years, $7.7 million for the 2003 return-to-actual true-up and $2.7 million from revisions to benefits related to asset and foreign power sales. Excluding the tax benefits, the effective rate for 2004 would have been 28.9 percent.
In 2003, income tax benefits of $36 million were recorded to reflect the resolution of tax audit issues related to prior years. The tax issues resolved during 2003 included the tax deductibility of certain merger costs associated with the mergers to form Xcel Energy and New Century Energies, Inc. (NCE) and the deductibility, for state purposes, of certain tax benefit transfer lease benefits. Excluding these tax benefits, the effective rate for 2003 would have been 29.7 percent. See Note 10 to the Consolidated Financial Statements.
Other Nonregulated Subsidiaries and Holding Company Results
The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results:
Eloigne Company - Eloigne invests in affordable housing that qualifies for federal and state tax credits. Eloigne’s earnings contribution is expected to decline slightly each year as tax credits on mature affordable housing projects begin to decline.
Planergy - Planergy provided energy management services. Planergy’s losses were lower in 2004 due to the dissolution of its business. Its losses were lower in 2002 largely due to pretax gains of approximately $8 million from the sale of a portfolio of energy management contracts, which reduced losses by approximately 2 cents per share.
Financing Costs and Preferred Dividends - Nonregulated 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.
In November 2002, the Xcel Energy holding company issued temporary financing, which included detachable options for the purchase of Xcel Energy notes, which were convertible to Xcel Energy common stock. This temporary financing was replaced with long-term holding company financing in late November 2002. Costs incurred to redeem the temporary financing included a redemption premium of $7.4 million, $5.2 million of debt discount associated with the detachable option, and other issuance costs, which increased financing costs and reduced 2002 earnings by 2 cents per share.
The earnings-per-share impact of financing costs and preferred dividends for 2004 and 2003 included above reflects dilutive securities, as discussed further in Note 11 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 $15 million, or 4 cents per share, in 2004, and $11 million, or 3 cents per share, in 2003.
Holding Company Special Charges - During 2004, special charges at the holding company consisted of an accrual of $17.6 million for a settlement agreement related to shareholder lawsuits. See Note 2 to the Consolidated Financial Statements for further discussion of these special charges.
During 2002, NRG experienced credit-rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events ultimately led to the restructuring of NRG in late 2002 and its bankruptcy filing in May 2003. See Note 4 to the Consolidated Financial Statements. Certain costs related to NRG’s restructuring were incurred at the holding company level and included in continuing operations and reported as Special Charges. Approximately $12 million of these costs were incurred
in 2003 and $5 million were incurred in 2002, which reduced after-tax earnings by approximately 2 cents per share and 1 cent per share, respectively. Costs in 2003 included approximately $32 million of financial advisor fees, legal costs and consulting costs related to the NRG bankruptcy transaction. These charges were partially offset by a $20 million pension curtailment gain related to the termination of NRG employees from Xcel Energy’s pension plan. In 2003, Xcel Energy also recorded a $7 million charge in connection with the suspension of the formation of the independent transmission company TRANSLink. See Note 2 to the Consolidated Financial Statements for further discussion of these special charges.
Other Nonregulated - In 2003, Utility Engineering sold water rights, resulting in a pretax gain (reported as nonoperating income) of $15 million. The gain increased after-tax income by approximately 2 cents per share.
Statement of Operations Analysis - Discontinued Operations
A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:
Regulated Utility Results - Discontinued Operations
During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking, including its interest in Guardian Pipeline, LLC, and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.
Viking had minimal income in 2003, as it was sold in January of that year. Income from Viking was higher in 2002, compared with 2001, primarily due to increased revenues.
During January 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary Cheyenne. As a result of this agreement, Xcel Energy is reporting 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 at Dec. 31, 2004.
NRG Results - Discontinued Operations
Due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG, Xcel Energy’s share of NRG results for current and prior periods is now shown as a component of discontinued operations.
2004 NRG Results Compared with 2003 - As a result of NRG’s emergence from bankruptcy in December 2003, Xcel Energy did not retain an ownership interest in NRG after that date. Therefore, Xcel Energy financial statements do not contain any results of NRG operations in 2004. See Note 4 to the Consolidated Financial Statements and the following discussion for further information.
2003 NRG Results Compared with 2002 - As a result of NRG’s bankruptcy filing in May 2003, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 - “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provided for loss recognition by Xcel Energy until its investment in NRG was written off to zero, with further loss recognition to continue if its financial commitments to NRG existed beyond amounts already invested. Xcel Energy initially recorded more losses than the limitations allow as of June 30, 2003, but upon Xcel Energy’s divestiture of its interest in NRG, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment to NRG were reversed in the fourth quarter of 2003. This resulted in a noncash gain of $111 million, or 26 cents per share, for the quarter and an adjustment of the total NRG losses recorded for the year 2003 to $251 million, or 60 cents per share.
NRG’s results included in Xcel Energy’s earnings for 2003 were as follows:
* These represent NRG losses incurred in the first and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under the equity method of accounting limitations discussed previously.
Following its credit downgrade in July 2002, NRG experienced credit and liquidity constraints and commenced a financial and business restructuring, including a voluntary petition for bankruptcy protection. This restructuring created significant incremental costs and resulted in numerous asset impairments as the strategic and economic value of assets under development and in operation changed.
NRG’s asset impairments and related charges in 2003 were approximately $540 million related to its NEO landfill gas projects and equity investments, planned disposals of domestic and international projects, and regulatory developments and changing circumstances that adversely affected NRG’s ability to recover the carrying value of certain investments. As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results in excess of its financial commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess losses were reversed upon NRG’s emergence from bankruptcy in December 2003, as discussed previously.
In 2003, NRG’s operating results (excluding the unusual items discussed above) were affected by higher market prices due to higher natural gas prices and an increase in capacity revenues due to additional projects becoming operational in the later part of 2002. In addition, the sale of an NRG investment in 2002 resulted in a favorable impact in 2003 as the investment generated substantial equity losses in the prior years. The increase was offset by losses incurred on contracts in Connecticut due to increased market prices, increased operating expenses, contract terminations and liquidated damages triggered by NRG’s financial condition and additional restructuring charges.
During 2002, the tax filing status of NRG for 2002 and future years changed from being included as part of Xcel Energy’s consolidated federal income tax group to filing on a stand-alone basis.
Other Nonregulated Results - Discontinued Operations
On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren, a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 45,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif. As a result of the decision, Seren is accounted for as discontinued operations. The sale of such investment is expected to be completed by mid-2005.
During 2003, Xcel Energy’s board of directors approved management’s plan to exit businesses conducted by e prime and Xcel Energy International. e prime ceased conducting business in 2004. Also during 2004, Xcel Energy completed the sales of the Argentina subsidiaries of Xcel Energy International.
2004 Nonregulated Results Compared with 2003 -Results of discontinued nonregulated operations in 2004 include the impact of the sales of the Argentina subsidiaries of Xcel Energy International. The sales were completed in three transactions with a total sales price of approximately $31 million, including certain adjustments that reached finalization in the fourth quarter of 2004. Approximately $15 million was placed in escrow, which is expected to remain in place until at least the end of the first quarter of 2005, to support customary indemnity obligations under the sales agreement. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including the realization of approximately $7 million of income tax benefits realizable upon sale of the Xcel Energy International assets.
In addition, 2004 results from discontinued operations include the impact of an after-tax impairment charge for Seren, including disposition costs, of $143 million, or 34 cents per share. The impairment charge was recorded based on operating results, market conditions and preliminary feedback from prospective buyers.
2003 Nonregulated Results Compared with 2002 - Results of discontinued nonregulated operations, other than NRG, include an after-tax loss of $59 million, or 14 cents per share, for the disposal of Xcel Energy International’s assets, based on the estimated fair value of such assets. These losses from discontinued nonregulated operations also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.
Tax Benefits Related to Investment in NRG - Xcel Energy has recognized tax benefits related to the divestiture of NRG. These tax benefits, since related to Xcel Energy’s investment in discontinued NRG operations, also are reported as discontinued operations.
During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million. Based on the results of a 2003 preliminary tax basis study of NRG, Xcel Energy recorded $404 million of additional tax benefits in 2003. In 2004, the NRG basis study was updated and previously recognized tax benefits were reduced by $16 million.
Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $405 million and $116 million of these tax benefits in 2004 and 2003, respectively, and expects to use $145 million in 2005. The remainder of the tax benefit carry forward is expected to be used over subsequent years.
Factors Affecting Results of Continuing Operations
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 service within their respective jurisdictions and affect our ability to recover our costs from customers. In addition, Xcel Energy’s nonregulated businesses have had an adverse impact on Xcel Energy’s earnings in 2004, 2003 and 2002. 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. The United States economy continues to show evidence of recovery as measured by growth in the gross domestic product. However, certain operating costs, such as those for insurance and security, have increased during the past three years due to economic uncertainty, terrorist activity and war or the threat of war. 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 slowdown in future economic growth.
Sales Growth
In addition to the impact of weather, customer sales levels in Xcel Energy’s regulated 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 estimated to be 1.8 percent in 2004 compared with 2003, and 1.5 percent in 2003 compared with 2002. Weather-normalized sales growth for firm natural gas utility customers was estimated to be approximately (1.9) percent in 2004 compared with 2003 and 1.6 percent in 2003 compared with 2002. Projections indicate that weather-normalized sales growth in 2005 compared with 2004 will be approximately 2.2 percent for retail electric utility customers and 1.1 percent for firm gas utility customers.
Pension Plan Costs and Assumptions
Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 12 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.
Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected investment returns experienced in prior years and decreases in interest rates used to discount benefit obligations. While investment returns exceeded the assumed level of 9.25 percent in 2003 and 9.0 percent in 2004, investment returns in 2001 and 2002 were below the assumed level of 9.5 percent and discount rates have declined from the 7.25-percent to 8-percent levels used in 1999 through 2002 cost determinations to 6.25 percent used in 2004. Xcel Energy continually reviews its pension assumptions and, in 2005, expects to change the investment return assumption to 8.75 percent and the discount rate assumption to 6.0 percent.
The investment gains or losses resulting from the difference between the expected pension returns assumed on smoothed or “market-related” asset levels and actual returns earned is deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost-determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on the use of average market-related asset values, and considering the expected recognition of past investment gains and losses over the next five years, achieving the assumed rate of asset return of 8.75 percent in each future year and holding other assumptions constant, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes in continuing operations will increase from a credit, or negative expense, of $27 million in 2004 to an expense of $8 million in 2005 and $20 million in 2006. Pension costs are currently a credit due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.
Xcel Energy bases its discount rate assumption on benchmark interest rates quoted by an established credit rating agency, Moody’s Investors Service (Moody’s), and has consistently benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2003, the annualized Moody’s Baa index rate was 6.61 percent and the Aaa index rate was 5.63 percent. The corresponding pension discount rate was 6.25 percent. At Dec. 31, 2004, the annualized Moody’s Baa index rate had declined 51 basis points to 6.10 percent, and the Aaa index rate had declined 20 basis points to 5.43 percent. Accordingly, the discount rate as of Dec. 31, 2004, was lowered 25 basis points to 6.00 percent. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2005 pension cost determinations.
If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impacts on the estimated pension costs recognized by Xcel Energy for financial reporting purposes:
• a 100 basis point higher rate of return, 9.75 percent, would decrease 2005 pension costs by $17.9 million;
• a 100 basis point lower rate of return, 7.75 percent, would increase 2005 pension costs by $17.9 million;
• a 100 basis point higher discount rate, 7.0 percent, would decrease 2005 pension costs by $8.3 million; and
• a 100 basis point lower discount rate, 5.0 percent, would increase 2005 pension costs by $6.2 million.
Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be affected by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2005. Assuming that future asset return levels equal the actuarial assumption of 8.75 percent for the years 2005 and 2006, Xcel Energy projects, under current funding regulations, that no cash funding would be required for 2005 and cash funding of $9 million would be required for 2006. Actual performance can affect these funding requirements significantly. Current funding regulations are under legislative review in 2005 and, if not retained in their current form, could change these funding requirements materially.
Regulation
Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries are subject to extensive regulation by the SEC under the PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain non-power goods and services. In addition, the PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. See further discussion of financing restrictions under Liquidity and Capital Resources.
Xcel Energy’s utility subsidiaries also are regulated by the FERC and state regulatory commissions. 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 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 investment, sales growth, conservation and demand-side management efforts, and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in rate proceedings. The most recently authorized electric utility returns are 11.47 percent for NSP-Minnesota, 11.9 percent for NSP-Wisconsin, 10.75 percent for PSCo and 11.5 percent for SPS.
Most of the retail rates for Xcel Energy’s utility subsidiaries provide for periodic adjustments to billings and revenues to allow for recovery of changes in the cost of fuel for electric generation, purchased energy, purchased natural gas for resale and, in Minnesota and Colorado, conservation, energy-management program costs and certain other costs. In Colorado, certain purchased electric capacity costs are recovered through a rate-adjustment mechanism. In Minnesota, generally changes in purchased electric capacity costs are not recovered through these rate-adjustment mechanisms. For Wisconsin electric operations, where automatic cost-of-energy adjustment clauses are not allowed, the biennial retail rate review process and an interim fuel-cost hearing process provide the opportunity for rate recovery of changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In Colorado, PSCo had an interim adjustment clause that allowed for recovery of all prudently incurred electric fuel and purchased energy expenses in 2003. In 2004, PSCo generally recovered all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause. Additionally, this fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric commodity adjustment formula rate, and a sharing among shareholders and customers of certain gains and losses on trading margins. In 2004, PSCo estimated that energy costs incurred were lower than the commodity adjustment formula rate and accrued an incentive of $11.25 million at Dec. 31, 2004.
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 distribution system. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, in 2002 and 2003 approval was obtained from Colorado and Minnesota regulators to recover, through a rate surcharge, certain costs to upgrade plants and lower emissions in the Denver and Minneapolis-St. Paul
metropolitan areas. These rate recovery mechanisms are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.
Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on Xcel Energy’s results of operations in the period the write-off is recorded.
At Dec. 31, 2004, Xcel Energy reported on its balance sheet regulatory assets of approximately $851 million and regulatory liabilities of approximately $1.6 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. See Notes 1 and 18 to the Consolidated Financial Statements for further discussion of regulatory deferrals.
Tax Matters
Interest Expense Deductibility - PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies, known as COLI policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2004, would reduce earnings by an estimated $311 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2004, is approximately $368 million. Xcel Energy estimates its annual earnings for 2005 would be reduced by $40 million, after tax, which represents 9 cents per share, if COLI interest expense deductions were no longer available. See Note 16 to the Consolidated Financial Statements for further discussion.
Accounting for Uncertain Tax Positions - In late July 2004, the Financial Accounting Standards Board (FASB) discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. The FASB has not issued any proposed guidance, but an exposure draft may be released in the first quarter of 2005. Xcel Energy is unable to determine the impact or timing of any potential accounting changes required by the FASB, but such changes could have a material financial impact.
Environmental Matters
Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and wastes, 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 wastes were approximately:
• $133 million in 2004;
• $133 million in 2003; and
• $138 million in 2002.
Xcel Energy expects to expense an average of approximately $154 million per year from 2005 through 2009 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 on environmental improvements at regulated facilities were approximately:
• $20.9 million in 2004;
• $58.5 million in 2003; and
• $107.8 million in 2002.
The regulated utilities expect to incur approximately $221 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2005 and approximately $980 million of related expenditures during the period from 2006 through 2009. Approximately $171 million and $787 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the metropolitan emissions reduction project, which are recoverable from customers through cost-recovery mechanisms. See Notes 16 and 17 to the Consolidated Financial Statements for further discussion of Xcel Energy’s environmental contingencies.
Impact of Nonregulated Investments
In the past, Xcel Energy’s investments in nonregulated operations have 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 will continue to have such a significant impact on its results. Xcel Energy does not expect to make any material investments in nonregulated projects. Xcel Energy’s remaining nonregulated businesses may carry a higher level of risk than its traditional utility businesses.
Inflation
Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders.
Critical Accounting Policies and Estimates
Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of appropriate technical 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, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the Consolidated Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most significant 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 continually makes informed judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. For example:
• Probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators.
• The ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by our regulators, is assumed.
• Probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed.
• Projections are made regarding earnings on pension investments, and the salary increases provided to employees over their periods of service.
• Future cash inflows of operations are projected in order to assess whether they will be sufficient to recover future cash outflows, including the impacts of product price changes and market penetration to customer groups.
The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impacts of these factors as of Dec. 31, 2004.
Recently Implemented Accounting Changes
For a discussion of significant accounting policies, see Note 1 to the Consolidated Financial Statements.
Pending Accounting Changes
Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004) - “Share Based Payment” (SFAS No. 123R) - In December 2004, FASB issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 - “Accounting for Stock-Based Compensation.” Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment awards using the intrinsic value allowed by previous accounting requirements, which did not require any expense to be recorded on stock options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at least six factors identified in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs.
Previous accounting guidance allowed for compensation expense related to performance share plans to be reversed if the target was not met. However, under SFAS No. 123R, compensation expense for performance share plans that expire unexercised due to the company’s failure to reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit plan could not be reversed if the target was not met. Implementation of SFAS No. 123R is required for interim or annual periods beginning after June 15, 2005. Xcel Energy is required to adopt the provisions in the third quarter of 2005. Implementation is not expected to have a material impact on net income or earnings per share.
DERIVATIVES, RISK MANAGEMENT AND MARKET RISK
In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity related instruments, including derivatives, are subject to market risk. These risks, as applicable to Xcel Energy and its subsidiaries, are discussed in further detail below.
Commodity Price Risk - Xcel Energy and its subsidiaries are exposed to commodity price risk in their generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric power, natural gas, coal and fuel oil. Commodity price risk is also managed through the use of financial derivative instruments. Xcel Energy’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.
Short-Term Wholesale and Commodity Trading Risk - Xcel Energy’s subsidiaries conduct various commodity-marketing activities, including the purchase and sale of capacity, energy and energy-related instruments. These marketing activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. Xcel Energy’s risk management policy allows management to conduct the marketing activities within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.
Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 - “Accounting for Derivative Instruments and Hedging Activities,” as amended, while others are subject to the fair value requirements of this pronouncement.
The fair value of the commodity trading contracts for continuing operations as of Dec. 31, 2004, was as follows:
As of Dec. 31, 2004, the sources of fair value of the commodity trading and hedging net assets were as follows:
Commodity Trading Contracts
Hedge Contracts
- Prices actively quoted or based on actively quoted prices.
2 - Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.
Normal purchases and sales transactions, as defined by SFAS No. 133, as amended, have been excluded.
At Dec. 31, 2004, a 10-percent increase in market prices over the next 12 months for trading contracts would impact pretax income from continuing operations by approximately $(0.1) million, whereas a 10-percent decrease would impact pretax income from continuing operations by approximately $0.1 million. Hedge contracts are accounted for as a component of Other Comprehensive Income and would not directly impact earnings.
Xcel Energy’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. Xcel Energy utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas. Previously, Xcel Energy calculated VaR using a holding period of five days for electricity and two days for natural gas. However, the methodology was changed to ensure consistency in risk measurement across both commodities. Xcel Energy’s revised holding periods remain consistent with current industry practice. VaR using the current methodology for 2004 and previous methodology for 2003 are as follows:
As of Dec. 31, 2004, the calculated VaRs using the current methodology were:
(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.
As of Dec. 31, 2003, the calculated VaRs using the previous methodology were:
(a) Comprises transactions for both NSP-Minnesota and PSCo.
(b) Conducted by e prime, which is a discontinued operation.
Interest Rate Risk - Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
Xcel Energy engages in hedges of cash flow and fair value exposure. The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis, if required. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.
At Dec. 31, 2004 and 2003, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense by approximately $6.8 million and $0.8 million, respectively. See Note 14 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.
Xcel Energy and its subsidiaries also maintain trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning, which are subject to interest rate risk and equity price risk. As of Dec. 31, 2004 and 2003, these funds were invested primarily in domestic and international equity securities and fixed-rate fixed-income securities. Per NRC mandates, these funds may be used only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices, or interest rates do not have an impact on earnings.
Credit Risk - In addition to the risks discussed previously, Xcel Energy and its subsidiaries are exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
At Dec. 31, 2004, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $23.4 million, while a decrease of 10 percent would have resulted in a decrease of $14.4 million.
Foreign Currency Exchange Risk - Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in Notes 3 and 4 to the Consolidated Financial Statements, Xcel Energy no longer has material foreign currency exchange risk.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash provided by operating activities for continuing operations increased $19 million during 2004 compared with 2003 due to the timing of payments made for trade payables partially offset by increased inventory costs related to higher natural gas costs, which will be collected from customers in future periods. Cash provided by operating activities for discontinued operations decreased $580 million during 2004 compared with 2003. During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by tax benefits received.
Cash provided by operating activities for continuing operations decreased during 2003 compared with 2002 primarily due to decreases in recovery of deferred fuel costs. Cash provided by operating activities for discontinued operations decreased during 2003 compared with 2002 due to the de-consolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. The decrease was partially offset by tax benefits received in connection with the divestiture of NRG in 2003.
Cash used in investing activities for continuing operations increased $236 million during 2004 compared with 2003 primarily due to increased utility capital expenditures. Cash provided by investing activities for discontinued operations decreased $73 million during 2004 compared with 2003 primarily due to the receipt of proceeds from the sale of Viking in 2003.
Cash used in investing activities for continuing operations was approximately the same during 2003 compared with 2002 due to comparable utility construction expenditures. Cash flows for investing activities related to discontinued operations increased during 2003 compared with 2002 due to the de-consolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG had significant construction expenditures during 2002 prior to its financial difficulties.
Cash flow from financing activities related to continuing operations increased $252 million during 2004 compared with 2003 primarily due to increased short-term borrowings partially offset by a common stock repurchase.
Cash flows for financing activities related to continuing operations decreased during 2003 compared with 2002 due to refinancing activities in 2003 to better align Xcel Energy’s capital structure and manage the cost of capital given the improving credit quality of Xcel Energy and its subsidiaries. During 2003, Xcel Energy and its subsidiaries extinguished $1.3 billion of long-term debt and issued
approximately $1.7 billion of long-term debt, as shown in the Consolidated Statement of Capitalization. Cash flows for financing activities related to discontinued operations decreased during 2003 compared with 2002 due to the de-consolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG obtained financing in 2002 for its construction expenditures prior to experiencing its financial difficulties.
See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.
Capital Requirements
Utility Capital Expenditures, Nonregulated Investments and Long-Term Debt Obligations - The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2005, 2006 and 2007 are shown in the table below.
The capital expenditure forecast includes the 750-megawatt Comanche 3 coal-fired plant in Colorado and the MERP project, which will reduce the emissions of three NSP-Minnesota’s generating plants. The MERP project is expected to cost approximately $1 billion, with major construction starting in 2005 and finishing in 2009. Xcel Energy expects to recover the costs of the emission-reduction project through customer rate increases beginning in 2006. Comanche 3 is expected to cost approximately $1.35 billion, with major construction starting in 2006 and finishing in 2010. The Colorado commission has approved sharing one-third ownership of this plant with other parties. Consequently, Xcel Energy’s capital expenditure forecast includes $1 billion, approximately two-thirds of the total cost.
Xcel Energy is evaluating a potential investment in a wind generation project of approximately $165 million, currently not included in the capital expenditure forecast. A decision to move forward with this type of investment will be dependent on the extension of federal tax credits related to wind generation, favorable regulatory recovery and other business considerations.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. For more information, see Note 16 to the Consolidated Financial Statements.
Contractual Obligations and Other Commitments - Xcel Energy has contractual obligations and other commercial commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2004. See additional discussion in the Consolidated Statements of Capitalization and Notes 5, 6, 15 and 16 to the Consolidated Financial Statements.
(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2004, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $130.5 million.
(b) Obligations to purchase fuel for electric generating plants, and electricity and natural gas for resale. Certain contractual purchase obligations are adjusted based on indexes. However, the effects of price changes are mitigated through cost-of-energy adjustment mechanisms.
(c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $500 million of goods and services through the year 2020, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.
Common Stock Dividends - Future dividend levels will be dependent upon the statutory limitations discussed below, as well as Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors. Xcel Energy’s objective is to deliver the financial results that will enable the board of directors to grant annual dividend increases at a rate consistent with our long-term earnings growth rate. Xcel Energy’s dividend policy balances:
• projected cash generation from utility operations;
• projected capital investment in the utility businesses;
• reasonable rate of return on shareholder investment; and
• impact on Xcel Energy’s capital structure and credit ratings.
Under PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may only declare and pay dividends out of retained earnings. Xcel Energy had $397 million of retained earnings at Dec. 31, 2004, and expects to declare dividends as scheduled. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from the utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent. All utility subsidiaries are required under PUHCA to pay dividends only from retained earnings, and some must comply with covenant restrictions under credit agreements for debt to total capitalization ratios.
The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus surplus divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio at Dec. 31, 2004, was 80 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.
Capital Sources
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock and preferred securities to maintain desired capitalization ratios.
Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited under PUHCA in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it has received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005, up to $2.5 billion of common stock
and long-term debt and $1.5 billion of short-term debt at the holding-company level. Xcel Energy has issued $2.2 billion of long-term debt and common stock, including the $600 million credit facility that closed in November 2004 that replaced the previous $400 million facility.
On Dec. 17, 2004, Xcel Energy filed an application with the SEC requesting additional financing authorization beyond June 30, 2005. If approved, the new financing authority would extend through June 30, 2008. The new application requests the authority for Xcel Energy to issue up to $1.8 billion of new long-term debt, common equity and equity-linked securities and $1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt, common equity, equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion. Xcel Energy expects the SEC to issue an order prior to the expiration of the existing authorization.
Xcel Energy’s ability to issue securities under the financing authority is subject to a number of conditions. One of the conditions of the financing authority is that Xcel Energy’s consolidated ratio of common equity to total capitalization be at least 30 percent. As of Dec. 31, 2004, the common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued that is rated, be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 17, 2005, Xcel Energy’s senior unsecured debt was considered investment grade by Standard & Poor’s Ratings Services (Standard & Poor’s) and Moody’s Investors Services, Inc. (Moody’s).
Short-Term Funding Sources - Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures. Another significant short-term funding need is the dividend payment.
As of Feb. 17, 2005, Xcel Energy and its utility subsidiaries had the following credit facilities available to meet its liquidity needs:
* Includes short-term borrowings and letters of credit
** The credit facilities of NSP-Minnesota, PSCo and SPS are expected to be renewed as five-year revolving credit facilities through a pro-rata syndication prior to May 2005.
Operating cash flow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including rate recovery of costs; environmental regulation compliance and industry deregulation; changes in the trends for energy prices; and supply and operational uncertainties, which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.
Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 5 to the Consolidated Financial Statements. Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reflect the views of Moody’s and Standard & Poor’s. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company. As of Feb. 17, 2005, the following represents the credit ratings assigned to various Xcel Energy companies:
Note: Moody’s highest credit rating for debt is Aaa1 and lowest investment grade rating is Baa3. Standard & Poor’s highest credit rating for debt is AAA+ and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P1 to P3. NP denotes a nonprime rating. Standard & Poor’s ratings for commercial paper range from A1 to A3, B and C. As of Feb. 17, 2005, Moody’s had Xcel Energy and its operating utility subsidiaries on “stable outlook.” Standard & Poor’s also had Xcel Energy and its operating utility subsidiaries on “stable outlook.”
In the event of a downgrade of its credit ratings below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 15 to the Consolidated Financial Statements. Xcel Energy has no explicit rating triggers in its debt agreements.
Money Pool - In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. State regulatory commission approvals have been received for NSP-Minnesota, PSCo and SPS, and borrowing and lending activity for these utilities has commenced. On Jan. 18, 2005, NSP-Wisconsin submitted a letter to the Public Service Commission of Wisconsin (PSCW) withdrawing its request for approval to participate in the money pool arrangement after it became apparent the conditions likely to be imposed by the PSCW would have limited flexibility and reduced the economic benefits of NSP-Wisconsin’s participation. The borrowings or loans outstanding at Dec. 31, 2004, and the SEC approved short-term borrowing limits from the utility money pool are:
Registration Statements - Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2004, Xcel Energy had approximately 400 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2004, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:
• In February 2002, Xcel Energy filed a $1 billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration. Xcel Energy has approximately $400 million remaining under the $1 billion shelf registration filed with the SEC in 2000.
• In April 2001, NSP-Minnesota filed a $600 million, long-term debt shelf registration with the SEC. NSP-Minnesota has approximately $40 million remaining under this registration.
• PSCo has an effective shelf registration statement with the SEC under which $800 million of secured first collateral trust bonds or unsecured senior debt securities were registered. PSCo has approximately $225 million remaining under this registration.
Future Financing Plans
Xcel Energy generally expects to fund its operations and capital investments primarily through internally generated funds. Xcel Energy plans to renew its credit facilities at NSP-Minnesota, PSCo and SPS during 2005 and may refinance existing long-term debt or scheduled long-term debt maturities based on prevailing market conditions. The renewal of the credit facilities at NSP-Minnesota, PSCo and SPS is planned to be done with long-term credit facilities for which borrowings would be reflected as a long-term liability on the consolidated balance sheet. To facilitate its potential debt issuances, NSP-Minnesota may file a long-term debt shelf registration statement with the SEC for up to $1 billion in 2005.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance
Xcel Energy’s 2005 earnings per share (EPS) from continuing operations guidance and key assumptions are detailed in the following table.
Key Assumptions for 2005:
• Seren is held for sale and accounted for as discontinued operations;
• Normal weather patterns are experienced for 2005;
• Weather-adjusted retail electric utility sales growth of approximately 2.0 percent to 2.4 percent;
• Weather-adjusted retail natural gas utility sales growth of approximately 1.0 percent to 1.3 percent;
• A successful outcome in the $9.9 million NSP-Minnesota gas rate case;
• A successful outcome in the FERC rate case of approximately $5 million;
• Capacity costs are projected to increase by $15 million, net of capacity cost recovery;
• No additional margin impact associated with the fuel allocation issue at SPS;
• 2005 trading and short-term wholesale margins are projected to decline by approximately $30 million to $55 million;
• 2005 other utility operating and maintenance expense is expected to increase between 2 percent to 3 percent;
• 2005 depreciation expense is projected to increase approximately 7 percent to 8 percent;
• 2005 interest expense is projected to increase approximately $10 million to $15 million;
• Allowance for funds used during construction-equity is projected to be relatively flat;
• Xcel Energy continues to recognize COLI tax benefits of 9 cents per share in 2005;
• The effective tax rate for continuing operations is expected to be approximately 28 percent to 31 percent; and
• Average common stock and equivalents of approximately 426 million shares in 2005, based on the “If Converted” method for convertible notes.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
See Management’s Discussion and Analysis under Item 7, incorporated by reference.
Item 8
Item 8 - Financial Statements and Supplementary Data
See Item 15(a)-1 in Part IV for index of financial statements included herein.
See Note 20 of Notes to Consolidated Financial Statements for summarized quarterly financial data.
MANAGEMENT REPORT ON INTERNAL CONTROLS
The management of Xcel Energy is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy’s internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2004. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment we believe that, as of Dec. 31, 2004, the company’s internal control over financial reporting is effective based on those criteria.
Xcel Energy’s independent auditors have issued an audit report on our assessment of the company’s internal control over financial reporting. Their report appears on the following page.
/S/ WAYNE H. BRUNETTI
/S/ BENJAMIN G.S. FOWKE III
Wayne H. Brunetti
Benjamin G.S. Fowke III
Chairman and Chief Executive Officer
Vice President and Chief Financial Officer
March 3, 2005
March 3, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Xcel Energy Inc.
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. (a Minnesota Corporation) and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, common stockholders’ equity and other comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated statements of operations, stockholders (deficit) equity and cash flows of NRG Energy, Inc. (a wholly owned subsidiary of Xcel Energy Inc.) included in the consolidated financial statements of the Company, which statements reflect losses from discontinued operations net of tax of $3.5 billion for the year ended December 31, 2002. Such financial statements were audited by other auditors whose report has been furnished to us (which as to 2002 expresses an unqualified opinion and includes an explanatory paragraph describing conditions that raise substantial doubt about NRG Energy, Inc.’s ability to continue as a going concern), and our opinion, insofar as it relates to the amounts included for NRG Energy, Inc. for the period described above, is based solely on the report of such other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Xcel Energy Inc.
We have audited management’s assessment, included in the accompanying Management Report On Internal Controls, that Xcel Energy Inc.and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of December 31, 2004 of the Company and subsidiaries and our report dated March 3, 2005 expressed an unqualified opinion on those financial statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder
of NRG Energy, Inc.:
In our opinion, the consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholder’s (deficit)/equity (not presented separately herein) present fairly, in all material respects, and the results of operations and cash flows of NRG Energy, Inc. and its subsidiaries for the year ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with standards of the Public Company Accounting Oversight Board (United States) of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
The consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 and Note 29 to the consolidated financial statements, the Company is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 the Company entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, the Company and certain of its subsidiaries filed for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Thousands of dollars, except per share data)
See Notes to Consolidated Financial Statements.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)
See Notes to Consolidated Financial Statements.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
See Notes to Consolidated Financial Statements.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER
COMPREHENSIVE INCOME (LOSS)
See Notes to Consolidated Financial Statements.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)
See Notes to Consolidated Financial Statements.
(a) Resource recovery financing
(b) Pollution control financing
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Business and System of Accounts - Xcel Energy’s utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation - In 2004, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota; NSP-Wisconsin; PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WGI, an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. Discontinued utility operations include the activity of Viking, an interstate natural gas pipeline company that was sold in January 2003; BMG, a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne, a regulated electric and natural gas utility that was sold in January 2005. See Note 3 to the Consolidated Financial Statements for more information on the discontinued operations of Viking, BMG and Cheyenne.
Xcel Energy’s nonregulated subsidiaries in continuing operations include Utility Engineering Corp. (engineering, construction and design) and Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits). During 2003, Planergy International, Inc. (energy management solutions) closed and began selling a majority of its business operations, with final dissolution occurring in 2004.
During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc. (broadband communications services). NRG, Xcel Energy International, e prime and Seren are presented as components of discontinued operations. During 2003, Xcel Energy also divested its ownership interest in NRG, an independent power producer. On May 14, 2003, NRG filed for bankruptcy to restructure its debt. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. During 2003, the board of directors of Xcel Energy also approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy International and e prime. See Note 3 to the Consolidated Financial Statements.
Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O&M Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.
In 2004, Xcel Energy began consolidating the financial statements of subsidiaries in which it has a controlling financial interest, pursuant to the requirements of FASB Interpretation No. 46 as revised, (FIN No. 46). Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. As a result, Xcel Energy is required to consolidate a portion of its affordable housing investments made through Eloigne, which for periods prior to 2004 are accounted for under the equity method. As of Dec. 31, 2004, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $144 million and long-term liabilities were approximately $78 million, including long-term debt of $75 million. Investments of $51 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.
Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects for which it does not have a controlling financial interest. Under this method, a proportionate share of pre-tax income is recorded as equity earnings from investments in affiliates. In the consolidation process, all significant intercompany transactions and balances are eliminated. Xcel Energy has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis, consistent with industry practice. See Note 9 to the Consolidated Financial Statements.
Revenue Recognition - Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date
of the last meter reading are estimated and the corresponding unbilled revenue is estimated.
Xcel Energy’s utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, Xcel Energy presents its revenue net of any excise or other fiduciary-type taxes or fees. A summary of significant rate-adjustment mechanisms follows:
• In 2004, PSCo generally recovered all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause. This fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric commodity adjustment formula rate and a sharing among shareholders and customers of certain gains and losses on trading margins. In 2003, PSCo’s electric rates permitted recovery of 100 percent of prudently incurred electric fuel and purchased energy expense. In 2002, PSCo’s electric rates in Colorado were adjusted under an incentive cost-adjustment mechanism, which resulted in the sharing of cost increases and decreases with customers and sharing of trading margins.
• NSP-Minnesota’s rates include a cost-of-fuel-and-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.
• NSP-Wisconsin’s rates include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. In Wisconsin, requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel-cost hearing process.
• In Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test. NSP-Minnesota and PSCo operate under various service standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s rates include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.
• SPS’ rates in Texas provide electric fuel and purchased energy cost recovery. In New Mexico, SPS also has a monthly fuel and purchased power cost-recovery factor.
• NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell firm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms.
Commodity Trading Operations - All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the Consolidated Statement of Operations.
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Pursuant to the JOA approved by the FERC, some of the commodity trading margins are apportioned to the other operating utilities of Xcel Energy. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading results are recorded at fair market value in accordance with SFAS No. 133, as amended. In addition, commodity trading results include the impacts of any margin-sharing mechanisms. In 2003, Xcel Energy’s board of directors designated e prime as held for sale. e prime had conducted natural gas commodity trading activities. Consequently, e prime financial results are presented as discontinued operations. For more information, see Note 3 to the Consolidated Financial Statements.
Derivative Financial Instruments - Xcel Energy and its subsidiaries utilize a variety of derivatives, including commodity forwards, futures and options, index or fixed price swaps and basis swaps, to mitigate market risk and to enhance our operations. For further discussion of Xcel Energy’s risk management and derivative activities, see Note 14 to the Consolidated Financial Statements.
Property, Plant, Equipment and Depreciation - Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also includes costs associated with the engineering design of future generating stations and other property held for future use.
Xcel Energy determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1 percent, 3.0 percent and 3.4 percent for the years ended Dec. 31, 2004, 2003 and 2002, respectively.
Allowance for Funds Used During Construction (AFDC) - AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.
Decommissioning - Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses are deferred as regulatory assets or liabilities. In 2003, NSP-Minnesota adopted SFAS No. 143, which changed the accounting methodology for nuclear decommissioning costs. For more information on nuclear decommissioning and the impacts of adopting SFAS No. 143, see Note 17 to the Consolidated Financial Statements.
PSCo also previously operated a nuclear generating plant, which has been decommissioned and repowered using natural gas. PSCo’s costs associated with decommissioning were deferred and are being amortized consistent with regulatory recovery.
Nuclear Fuel Expense - Nuclear fuel expense, which is recorded as our nuclear generating plants use fuel, includes the cost of fuel used in the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the U.S. Department of Energy (DOE) for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel-enrichment facility.
Environmental Costs - Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can reasonably be estimated. Costs may be deferred as a regulatory asset based on an expectation that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy’s expected share of the cost is estimated and recorded. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which has the latitude to compensate for final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
Legal Costs - Litigation settlements are recorded when it is probable Xcel Energy is liable for the costs and the liability can be reasonably estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.
Income Taxes - Xcel Energy and its domestic subsidiaries file consolidated federal income tax returns. NRG and its domestic subsidiaries were included in Xcel Energy’s consolidated federal income tax returns prior to NRG’s March 2001 public equity offering. Xcel Energy and its domestic subsidiaries file combined and separate state income tax returns. NRG and one or more of its domestic subsidiaries were included in some, but not all, of these combined returns in 2002 and 2003. NRG will not be consolidated or combined in any of Xcel Energy’s income tax returns after 2003.
Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. In accordance with PUHCA requirements, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.
Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.
Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 18 to the Consolidated Financial Statements.
Use of Estimates - In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed or revised annually, if appropriate.
Cash and Cash Equivalents - Xcel Energy considers investments in certain debt instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds.
Restricted cash in 2003 consisted primarily of funds received from NRG to be used to collateralize in full existing agreements of Xcel Energy to indemnify NRG, which continued after the divestiture of NRG. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.
Inventory - All inventory is recorded at average cost, with the exception of natural gas in underground storage at PSCo, which until 2004 was recorded using last-in-first-out pricing (LIFO). Effective Jan. 1, 2004, PSCo changed its method of accounting for the cost of stored natural gas for its local distribution operations from the LIFO pricing method to the average cost pricing method. This change in accounting was approved by the CPUC and was accounted for as a cumulative effect in accordance with the CPUC authorization. The average cost method has historically been used for pricing stored natural gas by both NSP-Minnesota and NSP-Wisconsin, as well as by PSCo for natural gas stored for use in its electric utility operations.
The cumulative effect of this change in accounting principle resulted in an increase to natural gas storage inventory and a corresponding decrease to the deferred natural gas cost accounts of approximately $36 million as of Jan. 1, 2004. Of this amount, $33 million related to current natural gas storage inventory and $3 million related to long-term natural gas storage inventory. As natural gas costs are 100 percent recoverable for PSCo’s local natural gas distribution operations under PSCo’s natural gas cost-adjustment mechanism, the cumulative effect of this change had no impact on net income or earnings per share. Prior period financial statements were not restated since the CPUC authorized this change effective Jan. 1, 2004. Under the natural gas cost-adjustment mechanism, the decrease in the cost of natural gas reduced rates to retail natural gas customers in Colorado during 2004.
Regulatory Accounting - Our regulated utility subsidiaries account for certain income and expense items in accordance with SFAS No. 71 - “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:
• certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and
• certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See more discussion of regulatory assets and liabilities at Note 18 to the Consolidated Financial Statements.
Stock-Based Employee Compensation - Xcel Energy has several stock-based compensation plans. Those plans are accounted for using the intrinsic-value method. Compensation expense is not recorded for stock options because there is no difference between the market price and the purchase price at grant date. Compensation expense is recorded for restricted stock and stock units awarded to certain employees, which are held until the restriction lapses or the stock is forfeited. For more information on stock compensation impacts, see Note 11 to the Consolidated Financial Statements.
Intangible Assets - Intangible assets with finite lives are amortized over their economic useful lives and periodically reviewed for impairment. Beginning in 2002, goodwill is no longer being amortized, but is tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value.
Xcel Energy’s goodwill consisted primarily of project-related goodwill at Utility Engineering for 2004 and 2003. During 2004 and 2003, impairment testing resulted in write-downs of this goodwill of $0.8 million and $4.8 million, respectively.
Intangible assets with finite lives continue to be amortized, and the aggregate amortization expense recognized in both years ended Dec. 31, 2004 and 2003, were approximately $0.2 million and $0.2 million, respectively. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $0.1 million. Intangible assets consisted of the following:
Asset Valuation - On Jan. 1, 2002, Xcel Energy adopted SFAS No. 144 - “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supercedes previous guidance for measurement of asset impairments. Xcel Energy did not recognize any asset impairments as a result of the adoption. The method used in determining fair value was based on a number of valuation techniques, including present value of future cash flows.
Deferred Financing Costs - Other assets also included deferred financing costs, net of amortization, of approximately $44 million at Dec. 31, 2004. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt.
Reclassifications - Certain items in the statements of operations and the balance sheets have been reclassified from prior period presentation to conform to the 2004 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to organizational changes, such as the sale of Cheyenne and the planned divestiture of Seren and the related reclassification to discontinued operations.
2. Special Charges
Special charges included in Operating Expenses for the years ended Dec. 31, 2004, 2003 and 2002, include the following:
2004 Holding Company - Legal Settlement - In 2004, Xcel Energy recorded a $17.6 million pretax charge for the accrual of a January 2005 settlement agreement related to shareholder lawsuits. For further discussion regarding the legal settlement, see Note 16 to the Consolidated Financial Statements.
2003 TRANSLink Transmission Co., LLC - In 2003, Xcel Energy recorded a $7 million pretax charge in connection with the suspension of the activities related to the formation of TRANSLink. The charge was recorded as a reserve against loans made to TRANSLink Development Company, LLC, an interim start-up company. TRANSLink was an independent transmission-only company. The formation activity was suspended due to continued market and regulatory uncertainty.
2003 and 2002 Holding Company - NRG Restructuring Charges - In 2003 and 2002, the Xcel Energy holding company incurred approximately $12 million and $5 million, respectively, for charges related to NRG’s financial restructuring. Costs in 2003 included approximately $32 million of financial advisor fees, legal costs and consulting costs related to the NRG bankruptcy transaction. These charges were partially offset by a $20 million pension curtailment gain related to the termination of NRG employees from Xcel Energy’s pension plan, as discussed in Note 12 to the Consolidated Financial Statements.
2002 Regulatory Recovery Adjustment - SPS - During 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of industry restructuring costs in Texas, which was approved by the state regulatory commission in May 2002. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.
2002 Utility Restaffing - During 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility-operating and corporate-support areas of Xcel Energy. In 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries. All 564 of accrued staff terminations have occurred. See the summary of costs below.
Accrued Special Charges - The following table summarizes activity related to accrued special charges related to the 2001 utility restaffing, as described above, for 2004, 2003 and 2002:
* Reported on the balance sheet in Other Current Liabilities.
3. Discontinued Operations
Pursuant to the requirements of SFAS No. 144, Xcel Energy classified and accounted for certain assets as held for sale at Dec. 31, 2004 and 2003. SFAS No. 144 requires that assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. In accordance with the provisions of SFAS No. 144, assets held for sale are not depreciated.
Results of operations for divested businesses and the results of businesses held for sale are reported for all periods presented on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2004 and 2003 have been reclassified to assets and liabilities held for sale accounts in the accompanying Balance Sheet.
Regulated Utility Segment
During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking, including its interest in Guardian Pipeline, LLC, and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.
During January 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary Cheyenne. Black Hills Corp. purchased all the common stock of Cheyenne, including the assumption of outstanding debt of approximately $25 million, for approximately $90 million, plus a working capital adjustment to be finalized in the second quarter of 2005. The sale was completed on Jan. 21, 2005, and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued at Dec. 31, 2004.
NRG Segment
Change in Accounting for NRG in 2003 - Prior to NRG’s bankruptcy filing in May 2003, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 - “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provide for loss recognition by Xcel Energy until its investment in NRG is written off to zero, with further loss recognition to continue if its financial commitments to NRG exist beyond amounts already invested.
Prior to NRG entering bankruptcy, Xcel Energy recorded more losses than the limitations provide for as of June 30, 2003. Upon Xcel Energy’s divestiture of its interest in NRG in December 2003, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment to NRG were reversed. This resulted in an adjustment of the total NRG losses recorded for the year 2003 to
$251 million. Xcel Energy’s share of NRG’s results for all 2003 periods is reported in a single line item, Equity in Losses of NRG, as a component of discontinued operations. NRG’s 2003 results do reflect some effects of asset impairments and restructuring costs, as discussed below. Xcel Energy’s share of NRG results for 2002 was a loss of $3.4 billion, due primarily to asset impairments and other charges recorded in the third and fourth quarters of 2002 related to NRG’s financial restructuring.
NRG Asset Impairments - In 2002, NRG experienced credit-rating downgrades, defaults under numerous credit agreements, increased collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number of NRG assets in 2002. NRG completed an analysis of the recoverability of the asset-carrying values of its projects each period, factoring in the probability weighting of different courses of action available to NRG, given its financial position and liquidity constraints at the time of each analysis. This approach was applied consistently to asset groups with similar uncertainties and cash flow streams. As a result, NRG determined that many of its construction projects and its operational projects became impaired during 2002 and 2003 and should be written down to fair market value. In applying those provisions, NRG management considered cash flow analyses, bids and offers related to those projects.
NRG incurred $3.5 billion of asset impairments and estimated disposal losses related to projects and equity investments, respectively, with lower expected cash flows or fair values. These charges recorded by NRG in the third and fourth quarters of 2002 included write-downs of $2.3 billion and $983 million for projects in development and operating projects, respectively, and $196 million for impairment charges and disposal losses related to equity investments.
Approximately $2.5 billion of these NRG impairment charges in 2002 related to NRG assets considered held for use under SFAS No. 144 as of Dec. 31, 2002. For fair values determined by similar asset prices, the fair value represented NRG’s estimate of recoverability at that time, if the project assets were to be sold. For fair values determined by estimated market price, the fair value represented a market bid or appraisal received by NRG that NRG believed was best reflective of fair value at that time. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflected project-specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operation given assumed market conditions at that time.
NRG continued to incur asset impairments and related charges in 2003. Prior to its bankruptcy filing in May 2003, NRG recorded more than $500 million in impairment and related charges resulting from planned disposals of an international project and several projects in the United States, and to regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain merchant generation units in the northeastern United States.
Nonregulated Subsidiaries - All Other Segment
Seren - On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 45,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif. An after-tax impairment charge, including disposition costs, of $143 million, or 34 cents per share, was recorded in 2004. Xcel Energy expects to complete the sale in mid-2005.
Xcel Energy International and e prime - In December 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by its nonregulated subsidiaries Xcel Energy International and e prime. The exit of all business conducted by e prime was completed in 2004.
Results of discontinued nonregulated operations in 2004 include the impact of the sale of the Argentina subsidiaries of Xcel Energy International. The sales took place in a series of three transactions with a total sales price of approximately $31 million. Approximately $15 million of the sales price was placed in escrow, which is expected to remain in place until at least the end of the first quarter of 2005, to support Xcel Energy’s customary indemnity obligations under the sales agreement. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including the realization of approximately $7 million of income tax benefits realizable upon sale of the Xcel Energy International assets.
Results of discontinued nonregulated operations in 2003, other than NRG, include an after-tax loss expected on the disposal of all
Xcel Energy International assets of $59 million, based on the estimated fair value of such assets. The fair value represents a market bid or appraisal received that is believed to best reflect the assets’ fair value at Dec. 31, 2003. Xcel Energy’s remaining investment in Xcel Energy International at Dec. 31, 2003, was approximately $39 million. Losses from discontinued nonregulated operations in 2003 also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.
Tax Benefits Related to Investment in NRG - With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership interest in NRG. Xcel Energy has recognized tax benefits related to the divestiture. These tax benefits, since related to Xcel Energy’s investment in discontinued NRG operations, also are reported as discontinued operations.
During 2002, Xcel Energy recognized tax benefits of $706 million. This benefit was based on the estimated tax basis of Xcel Energy’s cash and stock investments already made in NRG, and their deductibility for federal income tax purposes. Based on the results of a 2003 study, Xcel Energy recorded $105 million of additional tax benefits in 2003, reflecting an updated estimate of the tax basis of Xcel Energy’s investments in NRG and state tax deductibility. Upon NRG’s emergence from bankruptcy in December 2003, an additional $288 million of tax benefit was recorded to reflect the deductibility of the settlement payment of $752 million, uncollectible receivables from NRG, other state tax benefits and further adjustments to the estimated tax basis in NRG. Another $11 million of state tax benefits were accrued earlier in 2003 based on projected impacts. In 2004, the NRG basis study was updated and previously recognized tax benefits were reduced by $16 million.
Summarized Financial Results of Discontinued Operations
The major classes of assets and liabilities held for sale and related to discontinued operations as of Dec. 31 are as follows:
4. NRG Bankruptcy
In June 2002, in response to NRG’s severe financial difficulties, Xcel Energy completed an exchange transaction, whereby Xcel Energy acquired a 100-percent interest in NRG through a tender offer and merger involving a tax-free exchange of 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock. Xcel Energy reacquired all of the 26 percent of NRG shares not then owned by Xcel Energy, which was accounted for as a purchase. The 25,764,852 shares of Xcel Energy stock issued were valued at $25.14 per share, based on the average market price of Xcel Energy shares for three days before and after April 4, 2002, when the revised terms of the exchange were announced and recommended by the independent members of the NRG board of directors. Including other costs of acquisition, this resulted in a total purchase price to acquire NRG’s shares of approximately $656 million. The process to allocate the purchase price to underlying interests in NRG assets, and to determine fair values for the interests in assets acquired, resulted in approximately $62 million of amounts being allocated to fixed assets related to projects where the fair values were in excess of carrying values, to prepaid pension assets and to other assets.
The continued financial difficulties at NRG, resulting primarily from lower prices for power and declining credit ratings, culminated in NRG and certain of its affiliates filing, on May 14, 2003, voluntary petitions in the U.S. Bankruptcy Court for the Southern District of New York for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. In December 2003, NRG
emerged from bankruptcy. As part of the reorganization, Xcel Energy completely relinquished its ownership interest in NRG. As part of the overall settlement, Xcel Energy agreed to pay $752 million to NRG to settle all claims of NRG against Xcel Energy, and claims of NRG creditors against Xcel Energy. In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors. In 2004, Xcel Energy paid $752 million to NRG. Xcel Energy met these cash requirements with cash on hand, including tax refund proceeds associated with the NRG bankruptcy and/or borrowings under its revolving credit facility.
5. Short-Term Borrowings
Credit Facilities - As of Dec. 31, 2004, Xcel Energy had the following credit facilities available:
The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and, depending on credit ratings, support for commercial paper borrowings. The borrowing rates under these lines of credit are based on either the bank’s prime rate or the applicable London Interbank Offered Rate (LIBOR) plus a borrowing margin.
At Dec. 31, 2004 and 2003, Xcel Energy and its continuing subsidiaries had approximately $312 million and $59 million, respectively, in notes payable to banks, drawn on these credit lines. The weighted average interest rate at Dec. 31, 2004, was 4.15 percent. Also, $82.2 million of letters of credit were outstanding at Dec. 31, 2004, as discussed in Note 15 to the Consolidated Financial Statements, of which approximately $62.2 million were outstanding under the above credit facilities, which further reduced amounts available under the lines. Subsequent to Dec. 31, 2004, SPS arranged for the extension of the maturity date of its credit facility to May 2005.
6. Long-Term Debt
Except for SPS, which does not currently have a first mortgage indenture, and other minor exclusions, all property of the utility subsidiaries is subject to the liens of their first mortgage indentures, which are contracts between the companies and their bondholders. In addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas.
The utility subsidiaries’ first mortgage bond indentures provide for the ability to have sinking-fund requirements. NSP-Minnesota, NSP-Wisconsin and PSCo have no sinking-fund requirements for current bonds outstanding.
Xcel Energy has a $600 million, five-year senior unsecured revolving credit facility that matures in November 2009. Xcel Energy has the right to request a one-time increase in the size of the credit facility by up to $100 million and to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval. A financial covenant for debt to total capitalization is included. As of Dec. 31, 2004, Xcel Energy had $140 million drawn on this line of credit, which was classified as long-term debt. In addition, $82.2 million of letters of credit were outstanding at Dec. 31, 2004, as discussed in Note 15 to the Consolidated Financial Statements, of which $18.5 million were outstanding under the Xcel Energy credit facility, which further reduced the amount available under the line.
Xcel Energy’s 2007 and 2008 series convertible senior notes are convertible into shares of Xcel Energy common stock at a conversion price of $12.33 per share. Conversion is at the option of the holder at any time prior to maturity. In addition, Xcel Energy must make additional payments of interest, referred to as protection payments, on the notes in an amount equal to any portion of regular quarterly per share dividends on common stock that exceeds $0.1875 that would have been payable to the holders of the notes if such holders had converted their notes on the record date for such dividend. On May 20, 2004, the board of directors of Xcel Energy voted to raise the quarterly dividend on its common stock from $0.1875 to $0.2075. Consequently, as of Dec. 31, 2004, a total of $1.4 million in additional interest expense has been recorded.
In February 2005, PSCo redeemed $110 million of its 7.25-percent first collateral trust bonds, originally scheduled to mature in 2024.
Maturities of long-term debt are:
7. Preferred Stock
At Dec. 31, 2004, Xcel Energy had six series of preferred stock outstanding, which were callable at its option at prices ranging from $102.00 to $103.75 per share plus accrued dividends. Xcel Energy can only pay dividends on its preferred stock from retained earnings absent approval of the SEC under PUHCA. See Note 11 to the Consolidated Financial Statements for a description of such restrictions.
The holders of the $3.60 series preferred stock are entitled to three votes for each share held. The holders of the other preferred stocks are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of directors necessary to constitute a majority of the board of directors. The holders of common stock, voting as a class, are entitled to elect the remaining directors.
The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred shares. However, at Dec. 31, 2004, there are no such shares outstanding. This chart shows data for first- and second-tier subsidiaries:
* The sale of Cheyenne was completed in January 2005.
8. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts
Southwestern Public Service Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2036. The securities were redeemable at the option of SPS after October 2001, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred securities. A certificate of cancellation was filed to dissolve SPS Capital I on Jan. 5, 2004.
NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2037. The preferred securities were redeemable at NSP Financing I’s option at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certificate of cancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.
PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, had $194 million of 7.60-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2038. The securities were redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. On June 30, 2003, PSCo redeemed the $194 million of trust preferred securities. A certificate of cancellation was filed to dissolve PSCo Capital Trust I on Dec. 29, 2003.
Distributions paid to preferred security holders were reflected as a financing cost in the Consolidated Statements of Operations, along with interest charges.
9. Generating Plant Ownership and Operation
Joint Plant Ownership - Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2004:
NSP-Minnesota is part owner of Sherco 3, an 860-megawatt, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. PSCo’s assets include approximately 320 megawatts of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.
Nuclear Plant Operation - NSP-Minnesota and four other utility companies formed the Nuclear Management Co. (NMC), and each of the five member companies retains a 20 percent ownership interest in the NMC. The NMC is an operating company that manages the operations, maintenance and physical security of eight nuclear generating units on six sites, including three units/two sites owned by NSP-Minnesota. NSP-Minnesota continues to own the plants, controls all energy produced by the plants, and retains responsibility for nuclear property and liability insurance and decommissioning costs. In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid NMC $314.7 million in 2004, $227.0 million in 2003 and $182.5 million in 2002.
10. Income Taxes
Xcel Energy’s share of NRG results for current and prior periods is shown as a component of discontinued operations, due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG. Accordingly, Xcel Energy’s tax benefits related to its investment in NRG are reported in discontinued operations.
Xcel Energy’s federal net operating loss and tax credit carry forwards are estimated to be $1.4 billion and $79 million, respectively. $1.2 billion of the net operating loss and $23 million of the tax credit carry forwards are accounted for in discontinued operations. The carry forward periods expire in 2023 and 2024. Xcel Energy also has a net operating loss carry forward in some states. The state carry forward periods expire between 2018 and 2024. A valuation allowance was recorded against $46 million of capital loss carry forwards related to the sales of Xcel Energy International subsidiaries, which are accounted for in discontinued operations. The capital loss carry forward period expires in 2009.
Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences:
Income taxes comprise the following expense (benefit) items:
The components of Xcel Energy’s net deferred tax liability from continuing operations (current and noncurrent portions) at Dec. 31 were:
11. Common Stock and Incentive Stock Plans
Common Stock and Equivalents - Xcel Energy has common stock equivalents consisting of convertible senior notes, restricted stock units and stock options, as discussed further.
The dilutive impacts of common stock equivalents affected earnings per share as follows for the years ending Dec. 31:
Incentive Stock Plans - Xcel Energy and some of its subsidiaries have incentive compensation plans under which stock options and other performance incentives are awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy’s earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock method. The options normally have a term of 10 years and generally become exercisable from three to five years after grant date or upon specified circumstances. The tables below include awards made by Xcel Energy and some of its predecessor companies, adjusted for the merger stock exchange ratio, and are presented on an Xcel Energy share basis.
Activity in stock options was as follows for the years ended Dec. 31:
Certain employees also may elect to receive shares of restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan. Restricted stock vests in equal annual installments over a three-year period from the date of grant. Xcel Energy reinvests dividends on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted
stock acquired through dividend reinvestment. Restricted stock has a value equal to the market-trading price of Xcel Energy’s stock at the grant date. Xcel Energy granted 65,090 shares of restricted stock in 2004 when the grant-date market price was $17.40. Xcel Energy did not grant any shares of restricted stock in 2003. Xcel Energy granted 50,083 shares of restricted stock in 2002 when the grant-date market price was $22.83. Compensation expense related to these awards was not significant.
On March 28, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan approved by the shareholders in 2000. Restrictions on the restricted stock units lapse upon the achievement of a 27-percent total shareholder return (TSR) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. Under no circumstances will the restrictions lapse until one year after the grant date. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. The TSR was met in the fourth quarter of 2003, and approximately $31 million of compensation expense was recorded at Dec. 31, 2003. The remaining cost of $10 million related to the 2003 restricted stock units was recorded in the first quarter of 2004. In January 2004, Xcel Energy’s board of directors approved the repurchase of up to 2.5 million shares of common stock to fulfill the requirements of the restricted stock unit exercise. On March 29, 2004, the restricted stock units lapsed, and Xcel Energy issued approximately 1.6 million shares of common stock.
On Dec. 9, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 2, 2004, Xcel Energy granted 836,186 restricted stock units and performance shares. The grant-date market price used to calculate the TSR for this grant is $17.03. No expense has been recorded for the 2004 restricted stock units as it is not currently probable they will be earned.
On Dec. 14, 2004, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 1, 2005, Xcel Energy granted 843,251 restricted stock units and performance shares. The grant-date market price used to calculate the TSR for this grant is $18.10.
Xcel Energy applies Accounting Principles Board Opinion No. 25 - “Accounting for Stock Issued to Employees” in accounting for stock-based compensation and, accordingly, no compensation cost is recognized for the issuance of stock options, as the exercise price of the options equals the fair-market value of Xcel Energy’s common stock at the date of grant. In December 2002, the FASB issued SFAS No. 148 - “Accounting for Stock-Based Compensation - Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro forma impact of applying SFAS No. 148 is as follows at Dec. 31:
Common Stock Dividends Per Share - Historically, Xcel Energy has paid quarterly dividends to its shareholders. For the first quarter of 2004, Xcel Energy paid dividends to its shareholders of $0.1875 per share. In each of the last three quarters of 2004, Xcel Energy paid dividends to its shareholders of $0.2075. For each of the four quarters of 2003, Xcel Energy paid dividends to its shareholders of $0.1875 per share. For each of the first two quarters of 2002, Xcel Energy paid dividends to its shareholders of $0.375 per share. In each of the third and fourth quarters of 2002, Xcel Energy paid dividends to its shareholders of $0.1875 per share.
Dividends on common stock are paid as declared by the board of directors.
Dividend and Other Capital-Related Restrictions - Under the PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may declare and pay dividends only out of retained earnings. In May 2003, Xcel Energy received authorization from the SEC to pay an aggregate amount of $152 million of common and preferred dividends out of capital and unearned surplus. Xcel Energy used this authorization to declare and pay approximately $150 million for its first- and second-quarter dividends in 2003. At Dec. 31, 2004, Xcel Energy’s retained earnings were approximately $396.6 million.
The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only and not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, the capitalization ratio at Dec. 31, 2004, was 81 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.
In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $833 million in additional cash dividends on common stock at Dec. 31, 2004.
Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited, under PUHCA, in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005, up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding company level. Xcel Energy has $2.2 billion of long-term debt outstanding and common stock at the holding company level, including the $600 million multi-year credit facility that was entered into during November 2004.
On Dec. 17, 2004, Xcel Energy filed an application with the SEC requesting additional financing authorization beyond June 30, 2005. If approved, the new financing authority would extend through June 30, 2008. The new application requests the authority for Xcel Energy to issue up to $1.8 billion of new long-term debt, common equity and equity-linked securities and $1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt, common equity, equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion. Xcel Energy expects the SEC to issue an order prior to the expiration of the existing authorization.
Xcel Energy’s ability to issue securities under the financing authority is subject to a number of conditions. One of the conditions of the financing authority is that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent. As of Dec. 31, 2004, such common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued that is rated, be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities that are rated must be rated investment grade by at least one nationally recognized rating agency. As of Dec. 31, 2004, Xcel Energy’s senior unsecured debt was considered investment grade by at least one nationally recognized rating agency.
Stockholder Protection Rights Agreement - In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.
12. Benefit Plans and Other Postretirement Benefits
Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefiting employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2004, NSP-Minnesota had 2,197 and NSP-Wisconsin had 414 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007. PSCo had 2,177 bargaining employees covered under a collective-bargaining agreement, which expires in May 2006. SPS had 739 bargaining employees covered under a collective-bargaining agreement, which expires in October 2005.
Pension Benefits
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.
Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
Pension Plan Assets - Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments, no cash investments and 20 percent in nontraditional investments, such as real estate, timber ventures, private equity and a diversified commodities index.
The actual composition of pension plan assets at Dec. 31 was:
During 2003, Xcel Energy entered into a number of hedging arrangements within the pension trust designed to provide protection from a loss of asset value in the event of a broad decline in equity prices. These arrangements were closed out in December 2004.
Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.8 percent, which is greater than the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments that can provide a higher-than-average return. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2002 were below the assumed level of 9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25 percent and in 2004 investment returns exceeded the assumed level of 9.0 percent. Xcel Energy continually reviews its pension assumptions. In 2005, Xcel Energy changed the investment-return assumption to 8.75 percent to reflect its current expectations of investment returns.
Benefit Obligations - A comparison of the actuarially computed pension-benefit obligation and plan assets, on a combined basis, is presented in the following table:
(a) $18.5 million of the 2004 prepaid pension asset and $18.7 million of the 2003 prepaid pension asset relates to Xcel Energy’s remaining obligation for companies that are now classified as discontinued operations.
During 2002, one of Xcel Energy’s pension plans became under-funded, and at Dec. 31, 2004, had projected benefit obligations of $694.4 million, which exceeded plan assets of $590.1 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $2.0 billion on Dec. 31, 2004. A minimum pension liability of $62.7 million was recorded related to the under-funded plan as of that date. A corresponding reduction in Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, also was recorded, as previously recorded prepaid pension assets were reduced to record the minimum liability. Net of the related deferred income tax effects of the adjustments, total Stockholders’ Equity was reduced by $106.0 million at Dec. 31, 2004, due to the minimum pension liability for the under-funded plan.
Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2002 through 2004 for Xcel Energy’s pension plans, and is not expected to require cash funding in 2005. PSCo elected to make voluntary contributions to its pension plan for bargaining employees of $30 million in 2003 and $9 million in 2004, and Cheyenne voluntarily contributed $1 million to its pension plan for bargaining employees in 2004.
Benefit Costs - The components of net periodic pension cost (credit) are:
(a) Includes pension credits related to discontinued operations of $4.7 million for 2004, $18.3 million for 2003 and $10.1 million for 2002. The 2003 credit is largely due to a $20.0 million curtailment gain related to termination of NRG employees as a result of the divestiture of NRG in December 2003.
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2005 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.
Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans were approximately $21.9 million in 2004, $15.9 million in 2003 and $18.3 million in 2002.
Until May 6, 2002, Xcel Energy had a leveraged employee stock ownership plan (ESOP) that covered substantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energy made contributions to this noncontributory, defined contribution plan to the extent it realized tax savings from dividends paid on certain ESOP shares. ESOP contributions had no material effect on Xcel Energy earnings because the contributions were essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocated leveraged ESOP shares to participants when it repaid ESOP loans with dividends on stock held by the ESOP.
In May 2002, the ESOP was terminated and its assets were combined into the Xcel Energy retirement savings 401(k) plan. The ESOP component of the 401(k) plan is no longer leveraged.
Xcel Energy’s leveraged ESOP held 10.7 million shares of Xcel Energy common stock at May 6, 2002. Xcel Energy excluded an average of 0.7 million uncommitted leveraged ESOP shares from 2002 earnings-per-share calculations. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and were used by Xcel Energy for the 2002 employer matching contribution to its 401(k) plan.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Xcel Energy discontinued contributing toward health care benefits for former NCE nonbargaining employees retiring after June 30, 2003. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NSP who retired after 1998, bargaining employees of the former NSP who retired after 1999 and nonbargaining employees of the former NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
In conjunction with the 1993 adoption of SFAS No. 106 - “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.
Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued
benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.
Plan Assets - Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. In 2004, the investment strategy for the union asset fund was changed to increase the exposure to equity funds. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
The actual composition of postretirement benefit plan assets at Dec. 31 was:
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Given the fairly short time period in which funding has been required, Xcel Energy does not consider the actual historical returns achieved by its postretirement health care fund asset portfolio to be significant in establishing long-term return assumptions. Instead, Xcel Energy considers the long-term return levels projected and recommended by investment experts, weighted for the target mix of asset categories in our portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:
(a) $0.7 million of the 2004 accrued benefit liability and $1.1 million of the 2003 accrued benefit liability relate to Xcel Energy’s remaining obligation for companies that are now classified as discontinued operations.
Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached also was increased from two years to six years. This trend assumption was used to value the actuarial benefit obligations at year-end 2004, and will be used in 2005 retiree medical cost determinations. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects:
The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc. nonbargaining employees who retire after July 1, 2003.
Xcel Energy’s subsidiary, Viking, was sold on Jan. 17, 2003. The sale created a one-time curtailment gain of $0.8 million. NRG participants withdrew from the retiree life plan, resulting in a $1.3 million one-time curtailment gain in 2003.
NRG employees’ participation in the Xcel Energy postretirement health care plan ended when NRG emerged from bankruptcy on Dec. 5, 2003. A settlement gain of $0.9 million was recognized.
Cash Flows - The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $73 million during 2005.
Benefit Costs -The components of net periodic postretirement benefit costs are:
(a) Includes amounts related to discontinued operations of $1.3 million of cost in 2004, $(1.9) million of cost in 2003 and $3.6 million of cost in 2002.
Impact of 2003 Medicare Legislation - On Dec. 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This new coverage is generally effective Jan. 1, 2006. Many of Xcel Energy’s retiree medical programs provide prescription drug coverage for retirees over age 65 with coverage at least equivalent to the benefit to be provided under Medicare. While retirees remain in Xcel Energy’s postretirement health care plan without participating in the new Medicare prescription drug coverage, Medicare will share the cost of Xcel Energy’s plan. This legislation has therefore reduced Xcel Energy’s share of the obligation for future retiree medical benefits.
As of Dec. 31, 2003, Xcel Energy had reduced the postretirement health care benefit obligation by $64.6 million due to the expected sharing of the cost of the program by Medicare under the new legislation. Also, beginning in 2004, the annual net periodic postretirement benefit cost was reduced by approximately $10 million as a result of the expected sharing of the cost of the program by Medicare, with similar savings expected in subsequent years. These estimated reductions do not reflect any changes that may result in future levels of participation in the plan or the associated per capita claims cost due to the availability of prescription drug coverage for Medicare-eligible retirees. Also, in reflecting this legislation, Medicare cost sharing for a plan has been assumed only if Xcel Energy’s projected contribution to the plan is expected to be at least equal to the Medicare Part D basic benefit.
Projected Benefit Payments
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans:
13. Detail of Interest and Other Income, Net of Nonoperating Expenses
Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 comprises the following:
14. Derivative Instruments
In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. Xcel Energy and its subsidiaries utilize, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below.
Utility Commodity Price Risk - Xcel Energy and its subsidiaries are exposed to commodity price risk in their generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric power, natural gas, coal and fuel oil. Commodity risk also is managed through the use of financial derivative instruments. Xcel Energy and its utility subsidiaries utilize these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost-recovery mechanism. Xcel Energy’s risk management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists.
Short-Term Wholesale and Commodity Trading Risk - Xcel Energy’s subsidiaries conduct various marketing and commodity trading activities, including the purchase and sale of electric capacity and energy and other energy related instruments. These activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. Xcel Energy’s risk management policy allows management to conduct the marketing activity within approved guideline and limitations as approved by our risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Interest Rate Risk - Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
Foreign Currency Exchange Risk - Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in Notes 3 and 4 to the Consolidated Financial Statements, Xcel Energy no longer has material foreign currency exchange risk.
Types of and Accounting for Derivative Instruments
Xcel Energy uses a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Operations, to the extent effective.
SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. Xcel Energy and its subsidiaries formally document hedging relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. Xcel Energy and its subsidiaries also formally assess, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.
Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; and hedging transactions for interest rate swaps and lock agreements are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.
Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that Xcel Energy and its subsidiaries are currently engaged in are discussed below.
Cash Flow Hedges
The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.
Commodity Cash Flow Hedges - Xcel Energy and its subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2004, Xcel Energy had various commodity-related contracts classified as cash flow hedges extending through 2009. Amounts deferred from current earnings are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy and energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale.
As of Dec. 31, 2004, Xcel Energy had no amounts accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.
Xcel Energy had no ineffectiveness related to commodity cash flow hedges during the years ended Dec. 31, 2004 and 2003.
Interest Rate Cash Flow Hedges - Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2004, Xcel Energy had net losses related to interest rate swaps of approximately $1.1 million accumulated in Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.
Xcel Energy and its subsidiaries also enter into interest rate lock agreements, including treasury-rate locks and forward starting swaps, that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2004, Xcel Energy had net gains related to settled interest rate lock agreements of approximately $1.4 million accumulated in Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.
Xcel Energy had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2004 and 2003.
Financial Impact of Qualifying Cash Flow Hedges - The impact of qualifying cash flow hedges on Xcel Energy’s Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following table:
Fair Value Hedges
The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.
Interest Rate Fair Value Hedges - Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed-rate debt. The fair market value of Xcel Energy’s interest rate swaps at Dec. 31, 2004, was a liability of approximately $8.3 million.
Hedges of Foreign Currency Exposure of a Net Investment in Foreign Operations
Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in Notes 3 and 4 to the Consolidated Financial Statements, Xcel Energy no longer has material foreign currency exposure.
Normal Purchases or Normal Sales Contracts
Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133, as amended, requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133, as amended, as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.
Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133, as amended. In June 2003, the Derivatives Implementation Group of the FASB issued Implementation Issue No. C20 (C20) to clarify the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended. Xcel Energy’s implementation of C20 in 2003 had no impact on earnings. However, certain contracts did require a one-time fair value adjustment as of Oct. 1, 2003. The result of this adjustment was the creation of a derivative liability with an offsetting regulatory asset to reflect expected recovery of the amounts from customers. The derivative liability and related regulatory asset will be amortized over the respective lives of the contracts. See Note 18 to the Consolidated Financial Statements.
Xcel Energy evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133, as amended. None of the contracts entered into within the commodity trading operations qualify for a normal designation.
Normal purchases and normal sales contracts are accounted for as executory contracts as required under GAAP.
The following discussion briefly describes the use of derivative commodity and financial instruments at Xcel Energy and its subsidiaries, and discloses the respective fair values at Dec. 31, 2004 and 2003.
Commodity Trading Instruments - At Dec. 31, 2004 and 2003, the fair value of commodity trading contracts was $0.0 million and $4.2 million, respectively.
Regulated Commodity Instruments - The fair value of qualifying cash flow hedges is presented as a component of Other Comprehensive Income in the Consolidated Statements of Stockholders’ Equity. At Dec. 31, 2004 and 2003, the fair value of these contracts was $(24.6) million and $(11.2) million, respectively.
Nonregulated Commodity Instruments - Xcel Energy’s nonregulated operations use a combination of energy futures and forward contracts, along with physical supply, to hedge market risks in the energy market. At Dec. 31, 2004 and 2003, the fair value of these contracts was $0.0 million and $1.5 million, respectively. The fair value of cash flow hedges related to nonregulated operations for 2003 is included in discontinued operations.
Financial Instruments - Xcel Energy and its subsidiaries had interest rate swaps outstanding with a fair value that was a liability of approximately $30 million at Dec. 31, 2004. On Dec. 31, 2003, subsidiaries of Xcel Energy had interest rate swaps outstanding with a fair value that was a liability of approximately $18 million.
15. Financial Instruments
The estimated Dec. 31 fair values of Xcel Energy’s financial instruments, separately identifying amounts that are within continuing operations and within discontinued operations, are as follows:
The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair values of Xcel Energy’s long-term investments, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. The fair values of Xcel Energy’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.
The fair value estimates presented are based on information available to management as of Dec. 31, 2004 and 2003. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.
Xcel Energy provides guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantee. Unless otherwise indicated below, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral.
On Dec. 31, 2004, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to e prime Energy Marketing, Inc., e prime Florida, Inc., Cheyenne and Seren, which are components of discontinued operations:
(a) Nonperformance and/or nonpayment.
(b) Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement.
(c) Includes one performance bond with a notional amount of $11.1 million that guarantee the performance of Planergy Housing Inc., a subsidiary of Xcel Energy that was sold to Ameresco Inc. on Dec. 12, 2003. Ameresco Inc. has agreed to indemnify Xcel Energy for any liability arising out of any surety bond.
(d) Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
(e) Non-timely payment of the obligations or at the time the debtor becomes the subject of bankruptcy or other insolvency proceedings.
(f) Security interest in underlying receivable agreements.
(g) Xcel Energy agreed to indemnify an insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up to $80 million. The Xcel Energy indemnification will be triggered only in the event that Utility Engineering has failed to meet its obligations to the surety company.
(h) The guarantees associated with Cheyenne were terminated upon consummation of the sale on Jan. 21, 2005.
Letters of Credit
Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2004, there was $82.2 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.
16. Commitments and Contingencies
Commitments
Legislative Resource Commitments - In 1994 and 2003, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent-fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Commitments related to the 17 dry cask storage containers approved in 1994 have been fulfilled. The use of 29 dry
cask storage containers has been approved. As of Dec. 31, 2004, NSP-Minnesota had loaded 17 of the containers.
On May 29, 2003, the Minnesota Legislature enacted legislation that will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant, in addition to those approved in 1994. This will allow NSP-Minnesota to continue to operate the plant and store spent-fuel in the facility until its licenses with the Nuclear Regulatory Commission (NRC) expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. The legislation requires NSP-Minnesota to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.
The legislation also requires payments during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously established Renewable Development Fund from $8.5 million in 2002 to $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. All of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost-recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to store or dispose of the spent-fuel out of state, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.
Capital Commitments - As discussed in Liquidity and Capital Resources under Management’s Discussion and Analysis, the estimated cost, as of Dec. 31, 2004, of the capital expenditure programs and other capital requirements of Xcel Energy and its subsidiaries is approximately $1.5 billion in 2005, $2.3 billion in 2006 and $1.8 billion in 2007.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.
Leases - Xcel Energy and its subsidiaries lease a variety of equipment and facilities used in the normal course of business. Some of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2029. The net book value of property under capital leases was approximately $48.9 million and $47.7 million at Dec. 31, 2004 and 2003, respectively. Assets acquired under capital leases are recorded as property at the lower of fair market value or the present value of future lease payments, and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.
The remainder of the leases, primarily real estate leases and leases of coal-hauling railcars, trucks, cars and power-operated equipment are accounted for as operating leases. Rental expense under operating lease obligations for continuing operations was approximately $57.5 million, $65.0 million and $67.8 million for 2004, 2003 and 2002, respectively.
Expected operating lease expenses and future commitments under capital leases for continuing operations are:
Technology Agreement - Xcel Energy has a contract that extends through 2011 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at our option, although there are financial penalties for early termination. In 2004, Xcel Energy paid IBM $152.5 million under the contract and $24.5 million for other project business. The contract also has a committed minimum payment each year from 2005 through 2011.
Fuel Contracts - Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2005 and 2025. In total, Xcel Energy is committed to the minimum purchase of approximately $2.2 billion of coal, $133.1 million of nuclear fuel and $2.8 billion of natural gas, including $1.0 billion of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of increased costs, from market price changes in fuel is mitigated through the use of natural gas and energy cost adjustment mechanisms of the ratemaking process, which provide for pass through of most fuel costs to customers.
Purchased Power Agreements - The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indexes. However, the effects of price adjustments are mitigated through cost-of-energy adjustment mechanisms.
At Dec. 31, 2004, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:
Environmental Contingencies
Xcel Energy is subject to regulations covering air and water quality, land use, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. Compliance is continually assessed. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating facilities.
Site Remediation - Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2004, there were three categories of sites:
• the site of a former federal uranium enrichment facility;
• sites of former manufactured gas plants (MGPs) operated by our subsidiaries or predecessors; and
• third-party sites, such as landfills, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.
Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.
To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.
Estimates are revised as facts become known. At Dec. 31, 2004, the liability for the cost of remediating these sites was estimated to be $44.0 million, of which $19.3 million was considered to be a current liability. Some of the cost of remediation may be recovered from:
• insurance coverage;
• other parties that have contributed to the contamination; and
• customers.
Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for Xcel Energy’s future costs for these sites.
Federal Uranium Enrichment Facility
Approximately $5.4 million of the long-term liability and $4.6 million of the current liability relate to a DOE assessment to NSP-Minnesota and PSCo for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 17 to the Consolidated Financial Statements for further discussion of nuclear obligations.
Manufactured Gas Plant Sites
Levee Station Manufactured Gas Plant Site - A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station MGP site. The Levee Station was a coke-oven gas purification, storage and distribution facility. The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s. In the 1950s, the facility was demolished, and the High Bridge coal yard was extended onto the property. In the 1990s, the site was investigated and partially remediated at a cost of approximately $2.9 million. In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of the MERP, on the site of the Levee Station. The construction of the new plant will require the removal of buried structures and soil and groundwater remediation. Remediation activities will begin in 2005. The cost of the additional remediation is estimated to be $5.8 million, which will be accounted for as a capital expenditure of the MERP project.
Ashland MGP Site - NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon Bay adjoining the park.
As an interim action, Xcel Energy proposed, and the Wisconsin Department of Natural Resources (WDNR) approved, a coal tar removal and groundwater treatment system for one area of concern at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer under the MGP site to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002, a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.
On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the U. S. Environmental Protection Agency (EPA) in determining which sites require further investigation. On Nov. 14, 2003, the EPA and NSP-Wisconsin signed an administrative order on consent requiring NSP-Wisconsin to complete the remedial investigation and feasibility study for the site. On Dec. 7, 2004, the EPA approved NSP-Wisconsin’s proposed work plan with minor contingencies to complete the remedial investigation and feasibility study. On Feb. 1, 2005, NSP-Wisconsin submitted its revised work plan to the EPA addressing all of the contingencies raised with the previous proposal. The final approval results in specific delineation of the investigative fieldwork and scientific assessments that must be performed. The estimated cost of carrying out the work plan is $1.3 million in 2005. Resolution of Ashland remediation issues is not currently expected until 2007 or 2008. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.
The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, the ultimate cost of remediating the Ashland site is not determinable. On July 2, 2004, the WDNR sent NSP-Wisconsin an invoice for recovery of past costs incurred at the Ashland site between 1994 and March 2003 in the amount of $1.4 million. On Oct. 19, 2004, the WDNR, represented by the Wisconsin Department of Justice, filed a lawsuit in Wisconsin state court for reimbursement of the past costs. This lawsuit has been stayed until further action by either party. NSP-Wisconsin is reviewing the invoice to determine whether all costs charged are appropriate. All appropriate insurance carriers have been notified of the WDNR’s invoice and the lawsuit and will be invited to participate in any future efforts to address the WDNR’s actions. All costs paid are expected to be recoverable in rates.
NSP-Wisconsin has recorded a liability of $17.3 million for its estimate of its share of the cost of remediating the Ashland site, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site based on an expectation that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed as part of the Wisconsin biennial retail rate case process for prudence. Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years. In addition, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers.
Fort Collins MGP Site - Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. Recently, an oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. In early 2004, PSCo completed implementation of a work plan to further investigate the sources of contamination of the river at a cost of approximately $1.4 million. The work resulted in removal of contaminated sediments and delineation of the extent of the contamination.
On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo will perform remediation and monitoring work at an estimated cost of $8.8 million. Work is currently under way, with completion of construction anticipated in June 2005 followed by ongoing operation and maintenance.
To date, PSCo has spent approximately $3.4 million on the project, including settlement costs negotiated with the City of Fort Collins in 1998 and costs incurred by the EPA. The EPA is also expected to seek recovery of its ongoing oversight costs from PSCo. PSCo has deferred the costs recorded to date as a regulatory asset and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.
Third Party and Other Environmental Site Remediation
Asbestos Removal - Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since the intent is to operate most of these facilities indefinitely, Xcel Energy cannot estimate the amount or timing of payments for final removal of the asbestos. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Federal Clean Water Act - The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy to perform additional environmental studies at 12 power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Preliminary cost estimates range from less than $1 million at some plants to more than $10 million at others, depending on site-specific circumstances. Based on the limited information available, total capital costs to Xcel Energy are estimated at approximately $59 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.
Leyden Gas Storage Facility - In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (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. In 2003, PSCo began flooding the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo. In August 2003, the Colorado Oil and Gas Conservation Commission (COGCC) approved the closure plan, the last formal regulatory approval necessary before conversion. Leyden is expected to close by Dec. 31, 2005, and the city of Arvada will take over the site. PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2004, PSCo has incurred approximately $4.8 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo has accrued an additional $1.3 million of costs expected to be incurred through 2006 to complete the decommissioning and closure of the facility. PSCo has deferred these costs as a regulatory asset and believes that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.
In December 2003, a homeowners association petitioned the EPA to assess the threat of a natural gas release from the Leyden facility pursuant to Section 105(d) of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, (CERCLA) 42 U.S.C. section 9605. The EPA completed its review in October 2004 and concluded that the risk to nearby residents is relatively low. The EPA referred the matter to its Resource Conservation and Recovery Act program. On Nov. 24, 2004, the EPA sent a letter to the COGCC requesting that the COGCC contact Xcel Energy and request certain information concerning the closure. To date no formal request has been received by PSCo.
PSCo Notice of Violation - On Nov. 3, 1999, the U.S. Department of Justice filed suit against a number of electric utilities for alleged violations of the federal Clean Air Act’s New Source Review (NSR) requirements. The suit is related to alleged modifications of electric generating plants located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information requests related to PSCo plants in Colorado.
On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid-to-late 1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations, or are otherwise not subject
to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment-replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with PSCo in September 2002 to discuss the NOV.
If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require PSCo to install additional emission-control equipment at the plants and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation, commencing from the date the violation began. The ultimate financial impact to PSCo is not determinable at this time.
NSP-Minnesota NSR Information Request - On Nov. 3, 1999, the U. S. Department of Justice filed suit, related to alleged modifications of electric generating plants located in the South and Midwest, against a number of electric utilities for alleged violations of the Clean Air Act’s NSR requirements. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, the EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy completed its response to the follow-up information request during the fall of 2002.
Polychlorinated Biphenyl (PCB) Storage and Disposal - In August 2004, SPS received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contends the fine for the alleged violation is approximately $1.2 million. SPS is contesting the fine and is in discussions with the EPA.
Nuclear Insurance - NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $6.9 million for business interruption insurance and $26.1 million for property damage insurance if losses exceed accumulated reserve funds.
Legal Contingencies
In the normal course of business, Xcel Energy is subject to claims and litigation arising from prior and current operations. Xcel Energy is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.
Bender et al. vs. Xcel Energy - On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated ERISA by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment. A hearing for this motion is scheduled for April 21, 2005.
Carbon Dioxide Emissions Lawsuit - On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S Congress and the president. The ultimate financial impact of these lawsuits, if any, is not determinable at this time.
The issue of global climate change is receiving increased attention. Debate continues in the scientific community concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed, and the ultimate impacts that might result from a changing climate. There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue. The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005. President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies. Xcel Energy is closely monitoring the issue from both scientific and policy perspectives. While it is not possible to know the eventual outcome, Xcel Energy believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible future outcomes. Xcel Energy is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009 and to reduce carbon intensity by 7 percent by 2012. In certain jurisdictions, the evaluation process for future generating resources incorporates the risk of future carbon limits through the use of a carbon cost adder or externality costs. Xcel Energy also is involved in other projects to improve available methods for managing carbon.
Department of Labor Audit - In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998. The DOL has offered to conclude the audit at this time if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million. On July 19, 2004, Xcel Energy formally responded with a letter to the DOL that asserted no fiduciary violations have occurred and extended an offer to meet to discuss the matter further. If the DOL offer is put into effect, the requested contribution would affect cash flows only and not the net income of Xcel Energy.
Xcel Energy Inc. Securities Class Action Litigation - On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy’s common stock between Jan. 31, 2001, and July 26, 2002, was filed in the U.S. District Court for the District of Minnesota. The complaint named Xcel Energy and current and former Xcel Energy and NRG executives as defendants. Among other things, the complaint alleged violations of Section 10(b) of the Securities Exchange Act and Rule 10(b-5) related to allegedly false and misleading disclosures concerning various issues including but not limited to “round trip” energy trades, the nature, extent and seriousness of liquidity and credit difficulties at NRG and the existence of cross-default provisions (with NRG credit agreements) in certain of Xcel Energy’s credit agreements. After filing the lawsuit, several additional lawsuits were filed with similar allegations and all have been consolidated. On Jan. 14, 2005, the District Court issued an order of preliminary approval for a settlement reached by the parties. Under the terms of the settlement, the plaintiffs are to receive $80 million, with Xcel Energy’s insurance carriers paying $62.5 million, and Xcel Energy paying $17.5 million. Xcel Energy’s portion of the settlement payment was accrued at Dec. 31, 2004. A hearing to consider final approval of the settlement is scheduled for April 1, 2005.
Xcel Energy Inc. Shareholder Derivative Action - Edith Gottlieb vs. Xcel Energy Inc. et al; Essmacher vs. Brunetti; McLain vs. Brunetti - In August 2002, a shareholder derivative action was filed in the U.S. District Court for the District of Minnesota (Gottlieb), purportedly on behalf of Xcel Energy, against the directors and certain present and former officers, citing allegedly false and misleading disclosures concerning various issues and asserting breach of fiduciary duty. This action has been consolidated with other similar securities class actions and an amended complaint was filed. A settlement in the federal derivative lawsuit was reached in December 2004 and given preliminary approval by the District Court in an order dated Jan. 14, 2005. Under the terms of the settlement, Xcel Energy agreed to adopt certain corporate governance measures and pay plaintiff’s attorneys’ fees and expenses in an amount not to exceed $125,000. A hearing to consider final approval of this settlement is scheduled for April 1, 2005.
Xcel Energy Employee ERISA Actions - Newcome vs. Xcel Energy Inc.; Barday vs. Xcel Energy Inc. - On Sept. 23, 2002, and Oct. 9, 2002, two essentially identical actions were filed in the U.S. District Court for the District of Colorado, purportedly on behalf of classes of employee participants in Xcel Energy’s and its predecessors’ 401(k) or ESOP plans, from as early as Sept. 23, 1999, forward. The complaints in the actions name as defendants Xcel Energy, its directors, certain former directors and certain present and former officers. The complaints allege violations of the ERISA in the form of breach of fiduciary duty in allowing or encouraging purchase, contribution and/or retention of Xcel Energy’s common stock in the plans and making misleading statements and omissions in that regard. On Jan. 14, 2005, the District Court issued an order of preliminary approval related to a settlement reached by the parties. Under the terms of the settlement, plaintiffs are to receive a payment of $8 million, which will be paid by Xcel Energy’s insurance carrier. Xcel Energy also agreed, subject to the provisions of the applicable collective bargaining agreement, to undertake to amend the Xcel Energy 401(k) savings plan and its predecessor plans and the New Century Energies employees’ and stock ownership plan for bargaining unit and former nonbargaining unit employees, by permitting certain diversification of Xcel Energy stock held in participants’ accounts in portions of these plans. A hearing is scheduled for April 1, 2005, to consider final approval of this settlement.
SchlumbergerSema, Inc. vs. Xcel Energy Inc. (NSP-Minnesota) - Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling approximately $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserted counterclaims against SLB, including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also sought a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. In August 2004, the U.S. Bankruptcy Court for the District of Delaware ruled that claims related to use of certain equipment are barred unless NSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequent to the time of the assumption of this contract by SLB. If NSP-Minnesota cannot establish that basis, the decision would reduce NSP-Minnesota’s damage claim by approximately $5.5 million.
Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. - On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc., was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred to U.S. District Judge Pro in Nevada, who is supervising western areas wholesale natural gas marketing litigation. A motion is currently pending to transfer the case back to the Eastern District of California. The case is in the early stages, there has been no discovery and Xcel Energy intends to vigorously defend against these claims.
Cornerstone Propane Partners, L.P. et al. vs. e prime inc. et al. - On Feb. 2, 2004, a purported class action complaint was filed in the U.S. District Court for the Southern District of New York against e prime and three other defendants by Cornerstone Propane Partners, L.P., Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas futures and/or options contracts during the period from Jan. 1, 2000, to Dec. 31, 2002. The complaint alleges that defendants manipulated the price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange Act. In February 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. In February 2004, defendants, including e prime, filed motions to dismiss. In September 2004, the U.S. District Court denied the motions to dismiss. The case is in the early stages, there has been little discovery and Xcel Energy intends to vigorously defend against these claims.
Fairhaven Power Company vs. Encana Corporation et al. - On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. The case is in the early stages, there has been no discovery and Xcel Energy intends to vigorously defend against these claims.
Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. - On Nov. 29, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a
conspiracy with other sellers of natural gas to inflate prices. The case is in the early stages, there has been no discovery and Xcel Energy intends to vigorously defend against these claims.
Abelman Art Glass vs. Ercana Corporation, et al. - On Dec. 13, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. The case is in the early stages, there has been no discovery and Xcel Energy intends to vigorously defend against these claims.
Hill et al. vs. PSCo et al. - In late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into Xcel Energy distribution lines may have caused one or both fires. On Jan. 14, 2004, an action against PSCo relating to the fire in Boulder County was filed in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs assert that they are seeking in excess of $35 million in damages. Xcel Energy believes it has insurance coverage to mitigate the liability in this matter. The ultimate financial impact to PSCo is not determinable at this time.
Other Contingencies
Tax Matters - PSCo’s wholly owned subsidiary, PSRI, owns and manages permanent life insurance policies, known as COLI policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.
After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by tax law. Based upon this assessment, management believes that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.
In April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest for tax years 1993 and 1994. In December 2004, Xcel Energy filed suit in U.S. Tax Court in Washington D.C. for tax years 1995 through 1997. Xcel Energy expects to request that the tax court stay its petition pending the decision in the District Court litigation. The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position and results of operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.
Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2004, would reduce earnings by an estimated $311 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2004, is approximately $368 million. Xcel Energy estimates its annual earnings for 2004 would be reduced by $36 million, after tax, which represents 8 cents per share, if COLI interest expense deductions were no longer available.
Accounting for Uncertain Tax Positions - In late July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. The FASB has not issued any proposed guidance, but an exposure draft may be released in the first quarter of 2005. Xcel Energy is unable to determine the impact or timing of any potential accounting changes required by the FASB, but such changes could have a material financial impact.
SPS Retail Fuel Cost Recovery - Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed with the PUCT its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003. SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period. Intervenor and PUCT staff testimony was filed in October 2004 and hearings were held in December 2004. Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to wholesale sales, among other things. Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors. SPS has recorded its best estimate of any potential liability related to the impact of this proceeding. In January 2005, SPS filed its post-hearing briefs disputing the intervenor objections. Reply briefs were filed on Feb. 15, 2005, the administrative law judge is expected to issue his recommended proposal for decision by the end of April 2005, and PUCT action is expected by the end of May 2005. SPS is pursuing a settlement agreement with the parties involved.
17. Nuclear and Other Asset Retirement Obligations
Fuel Disposal - NSP-Minnesota is responsible for temporarily storing used or spent-nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $13 million in 2004, $13 million in 2003 and $13 million in 2002. In total, NSP-Minnesota had paid approximately $335 million to the DOE through Dec. 31, 2004. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.
The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.
NSP-Minnesota has its own temporary, on-site storage facilities for spent-fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.
Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2004 was $4.6 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $12.6 million at Dec. 31, 2004, is deferred as a regulatory asset.
Regulatory Plant Decommissioning Recovery - Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the years 2010 through 2048, assuming the prompt dismantlement method. NSP-Minnesota is currently accruing the costs for decommissioning over the MPUC approved cost-recovery period and including the accruals in Accumulated Depreciation. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing accruals are reclassified to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143.
Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005, seeking a certificate of need for dry spent-fuel storage, and plans to file an application in early 2005 with the NRC for an operating license extension of up to 20 years. A decision regarding Monticello relicensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years. The Prairie Island license renewal process has not yet begun.
Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.
The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. An original filing was submitted to the MPUC in October 2002 and updated in August 2003; final approval was received in December 2003.
The most recent cost estimate represents an annual increase in external fund accruals, along with the extension of Prairie Island cost recovery to the end of license life in 2014. The MPUC also approved the Department of Commerce recommendation to accelerate the internal fund transfer to the external funds effective July 1, 2003, ending on Dec. 31, 2005. This approval increased the fund cash contribution by approximately $29 million in 2003. Consistent with previous treatment, the transfers from the internal fund are effectively moving previously collected funds to the external fund, thereby reducing the external fund book expense. Based on the last MPUC approval requiring the acceleration of the internal fund transfer, there is a step change in the level of the overall decommissioning expense at the expiration of the transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. Xcel Energy believes future decommissioning cost accruals will continue to be recovered in customer rates.
The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2004, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.
At Dec. 31, 2004, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $768 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters. These amounts are not those recorded in the financial statements for the asset retirement obligation in accordance with SFAS No. 143:
Decommissioning expenses recognized include the following components:
Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated Balance Sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statement of Operations.
Negative accruals for internally funded portions in 2002, 2003 and 2004 reflect the impacts of the 1999 and 2002 decommissioning studies, which have approved an assumption of 100-percent external funding of future costs. Previous studies assumed a portion was funded internally; beginning in 2000, accruals are reversing the previously accrued internal portion and increasing the external portion prospectively.
Asset Retirement Obligations - Xcel Energy records future plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.
Asset retirement obligations have been recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability also has been recorded for the decommissioning of an NSP-Minnesota steam production plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. Pathfinder operated as a steam production peaking facility from 1969 until its retirement.
A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2004:
The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $986 million as of Dec. 31, 2004, including external nuclear decommissioning investment funds and internally funded amounts.
Removal Costs - Xcel Energy also accrues an obligation for plant removal costs for other generation, transmission and distribution facilities of its utility subsidiaries. Generally, the accrual of future non-legal removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.
Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs by entity are as follows at Dec. 31:
18. Regulatory Assets and Liabilities
Xcel Energy’s regulated businesses prepare their Consolidated Financial Statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy’s business that is not regulated cannot use SFAS No. 71 accounting. The components of unamortized regulatory assets and liabilities of continuing operations shown on the balance sheet at Dec. 31 were:
(a) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
(b) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments, as discussed previously in Note 17, and unamortized costs for PSCo’s Fort St. Vrain nuclear plant decommissioning.
(c) Excludes current portion expected to be returned to customers within 12 months of $12.4 million for 2004, and the 2003 current portion expected to be recovered from customers of $3.1 million
(d) Excludes current portion expected to be recovered within the next 12 months of $16.1 and $55.8 million for 2004 and 2003, respectively
19. Segments and Related Information
Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other.
• Xcel Energy’s Regulated Electric Utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Kansas and Oklahoma. It also makes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes commodity trading operations.
• Xcel Energy’s Regulated Natural Gas Utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:
• directly assigned wherever applicable;
• allocated based on cost causation allocators wherever applicable; and
• allocated based on a general allocator for all other costs not assigned by the above two methods.
The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided.
20. Summarized Quarterly Financial Data (Unaudited)
Summarized quarterly unaudited financial data is as follows:
(a) 2004 results include special charges in fourth quarter, as discussed in Note 2 to the Consolidated Financial Statements, and unusual items as follows:
• Results from continuing operations were decreased by the accrual of legal settlements incurred by the holding company in the amount of $17.6 million in the fourth quarter.
• Third-quarter results from discontinued operations were decreased by $112 million, or 27 cents per share, due to the estimated impairment expected to result from the disposal of Seren, as discussed in Note 3 to the Consolidated Financial Statements. During fourth quarter, an adjustment increasing the impairment by $31 million, or 7 cents per share was recorded.
• Fourth-quarter results from discontinued operations were decreased by $16 million, or 4 cents per share, related to a reduction of the NRG tax benefits previously booked, after completion of an NRG tax basis study.
• Fourth-quarter results from continuing operations were increased by $36 million, or 8 cents per share, due to the accrual of income tax benefits, including $28.9 million related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years, $4.4 million for the 2003 return-to-accrual true-up and $2.7 million for revisions to benefits related to asset and foreign power sales.
• Fourth-quarter results from continuing operations were decreased by an accrual recorded to reflect SPS’ best estimate of any potential liability for the impact of its retail fuel cost recovery proceeding in Texas.
(b) 2003 results include special charges in certain quarters, as discussed in Note 2 to the Consolidated Financial Statements, and unusual items as follows:
• Results from continuing operations were decreased for NRG-related restructuring costs incurred by the holding company in the amount of $1.4 million in the first quarter, $7.3 million in the second quarter and $3.0 million in the third quarter.
• Fourth-quarter results from continuing operations were increased by $22 million, or 3 cents per share, for adjustments made to depreciation accruals for the year, due to a regulatory decision approving the extension of NSP-Minnesota’s Prairie Island nuclear plant to operate over the license term.
• Fourth-quarter results from continuing operations were increased by $30 million, or 7 cents per share, from the resolution of income tax audit issues related to prior years.
• Fourth-quarter results from continuing operations were decreased by $7 million pretax, or 1 cent per share, for charges recorded related to the TRANSLink project due to regulatory and operating uncertainties.
• Fourth-quarter results from discontinued operations were increased by $111 million, or 26 cents per share, for reversal of equity in prior NRG losses due to the divestiture of NRG in December 2003, and increased by $288 million, or 68 cents per share, due to revisions to the estimated tax benefits related to Xcel Energy’s investment in NRG. See Note 3 to the Consolidated Financial Statements for further discussion of these items.
• Fourth-quarter results from discontinued operations were decreased by $59 million, or 14 cents per share, due to the estimated impairment expected to result from the disposal of Xcel Energy International’s Argentina assets, as discussed in Note 3 to the Consolidated Financial Statements, and by $16 million, or 4 cents per share, due to the accrual of e prime’s cost to settle an investigation by the Commodity Futures Trading Commission.
Item 9
Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
During 2003 and 2004, and through the date of this report, there were no disagreements with the independent public accountants on accounting principles or practices, financial statement disclosures, or auditing scope or procedures.
Item 9A
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. As of Dec. 31, 2004, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the chief executive officer (CEO) and the chief financial officer (CFO), of the effectiveness of our disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.
Internal Controls Over Financial Reporting
No change in Xcel Energy’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy has made a number of changes in its internal control over financial reporting during the most recent fiscal quarter in order to make the control environment more effective and efficient.
Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding reliability of our financial reporting. Xcel Energy has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the fourth quarter and in preparation for issuing its report for the year ended Dec. 31, 2004 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, we did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and approved by the SEC and as indicated in Management Report on Internal Controls herein, have concluded that our internal control over financial reporting was effective.
Item 9B
Item 9B - Other Information
None
PART III
Item 10
Item 10 - Directors and Executive Officers of the Registrant
Information required under this Item with respect to directors is set forth in Xcel Energy’s Proxy Statement for its 2005 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.
Item 11
Item 11 - Executive Compensation
Except as set forth below, information required under this Item is set forth in Xcel Energy’s Proxy Statement for its 2005 Annual Meeting of Shareholders, which is incorporated by reference.
On March 2, 2005, the Governance, Compensation & Nominating Committee (Committee) of the Xcel Energy board of directors approved payouts of annual incentive awards for 2004, pursuant to the 2004 Xcel Energy Annual Incentive Award Program. The payouts to the Named Executives of Xcel Energy were as follows:
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Information concerning the security ownership of the directors and officers of Xcel Energy and securities authorized for issuance under equity compensation plans is contained in Xcel Energy’s Proxy Statement for its 2005 Annual Meeting of Shareholders which is incorporated by reference.
Item 13
Item 13 - Certain Relationships and Related Transactions
Information concerning relationships and related transactions of the directors and officers of Xcel Energy is contained in Xcel Energy’s Proxy Statement for its 2005 Annual Meeting of Shareholders, which is incorporated by reference.
Item 14
Item 14 - Principal Accounting Fees and Services
Information concerning fees paid to the principal accountant for each of the last two years is contained in Xcel Energy’s Proxy Statement for its 2005 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15
Item 15 - Exhibits, Financial Statement Schedules
1.
Consolidated Financial Statements:
Management Report on Internal Controls - For the year ended Dec. 31, 2004.
Reports of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2004, 2003 and 2002.
Consolidated Statements of Operations - For the three years ended Dec. 31, 2004, 2003 and 2002.
Consolidated Statements of Cash Flows - For the three years ended Dec. 31, 2004, 2003 and 2002.
Consolidated Balance Sheets - As of Dec. 31, 2004 and 2003.
2.
Schedule I - Condensed Financial Information of Registrant.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2004, 2003 and 2002.
3.
Exhibits
4.94*
Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 - Exhibit 4(a)).
4.95*
Indentures supplemental to Indenture dated as of Oct. 1, 1993:
SCHEDULE I
CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
STATEMENTS OF OPERATIONS
See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.
CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
STATEMENTS OF CASH FLOWS
See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.
CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
BALANCE SHEETS
See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.
CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME
Incorporated by reference is Xcel Energy Inc. and Subsidiaries Consolidated Statements of Common Stockholders’ Equity and Other Comprehensive Income in Part II, Item 8.
See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.
SCHEDULE II
XCEL ENERGY INC.
AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Years Ended Dec. 31, 2004, 2003 and 2002
(1) Uncollectible accounts written off or transferred to other parties.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Wayne H. Brunetti
/s/ Richard C. Kelly
Wayne H. Brunetti
Richard C. Kelly
Chief Executive Officer and Chairman of the Board
President, Chief Operating Officer and Director
(Principal Executive Officer)
(Principal Operating Officer)
/s/ Benjamin G.S. Fowke III
/s/ Teresa S. Madden
Benjamin G.S. Fowke III
Teresa S. Madden
Vice President and Chief Financial Officer
Vice President and Controller
(Principal Financial Officer)
(Principal Accounting Officer)
*
*
Richard H. Anderson
C. Coney Burgess
Director
Director
*
*
David A. Christensen
Roger R. Hemminghaus
Director
Director
*
*
A. Barry Hirschfeld
Douglas W. Leatherdale
Director
Director
*
*
Albert F. Moreno
Ralph R. Peterson
Director
Director
*
*
A. Patricia Sampson
Margaret R. Preska
Director
Director
* /s/ Teresa S. Madden
Teresa S. Madden
Attorney-in-Fact