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Westar Energy 10-K 2006 Documents found in this filing:
Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K
For the fiscal year ended December 31, 2005 OR
For the transition period from to Commission File Number 1-3523
WESTAR ENERGY, INC. (Exact name of registrant as specified in its charter)
818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300 (Address, including Zip code and telephone number, including area code, of registrant’s principal executive offices)
Securities registered pursuant to section 12(b) of the Act:
Securities registered pursuant to section 12(g) of the Act: Preferred Stock, 4-1/2% Series, $100 par value (Title of Class)
Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes x No ¨ Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act). Check one: Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $2,081,879,276 at June 30, 2005. Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
DOCUMENTS INCORPORATED BY REFERENCE:
Table of ContentsTABLE OF CONTENTS
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Table of ContentsFORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning:
What happens in each case could vary materially from what we expect because of such things as:
These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.
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Table of ContentsITEM 1. BUSINESS GENERAL We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 660,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612. SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2005 Overview
Retail Rate Review December 28, 2005 KCC Order In accordance with a 2003 KCC order, we filed applications with the KCC on May 2, 2005 to review our rates. We requested an increase in our retail electric rates and the adoption of other practices under the KCC’s jurisdiction. While the KCC ordered a net increase in our base rates of $38.8 million annually, the increase is substantially offset by the requirement that we credit to retail customers a rolling three-year average of the margins we realize from our market-based wholesale sales. Other significant changes approved by the KCC are the RECA, an environmental cost recovery rider (ECRR), the separation of transmission delivery charges, an increase in annual depreciation expense, an extended recovery period for costs being recovered for which no return is provided and the recovery of various costs that have been incurred and deferred as regulatory assets.
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Table of ContentsRetail Energy Cost Adjustment: The RECA allows us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power. The adjustment is based on the actual cost of fuel and purchased power less margins from market-based wholesale sales. We have contracts with certain large industrial customers, the terms of which do not provide for the separate billing of fuel costs. Fuel costs for these customers will continue to be recovered through the rates specified in each of these contracts. These customers represented approximately 8% of our total retail sales volumes for 2005. Wholesale Sales Margins: The terms of the RECA require that we include, as a credit to recoverable fuel costs, an amount based on the average of the margins realized from market-based wholesale sales during the immediately prior three-year period. In any period we are unable to realize market-based wholesale sales margins at least equal to the amount of the credit, our financial results would be adversely affected. In the short-term, our generating capacity is fixed while the load requirements of our customers change constantly. When our generating capacity is not needed to serve our customers, we attempt to seek out wholesale sales of energy at prices in excess of the costs of production. We are likely to face the prospect of decreasing margins as the energy demands of our retail customers increase, which may result in crediting to retail customers an amount that would exceed the margins realized in the current period. Environmental Cost Recovery Rider: The ECRR allows for the timely inclusion in rates, without requiring a full rate review, of the capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act. Prior to collection through rates, the KCC will review any environmental expenditures to be considered for recovery under the ECRR. Any increased operating and maintenance costs that result from updating or adding environmental equipment cannot be recovered through the ECRR. These costs would be addressed in future rate reviews. Transmission Delivery Charge: The December 28, 2005 KCC Order allows us to separate our transmission costs from our base rates charged to retail customers. This allows us to implement a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs, which provides for adjustment on a more timely basis. These rates were proposed in an application filed with the Federal Energy Regulatory Commission (FERC) on May 2, 2005 and became effective on December 1, 2005, subject to refund upon review and approval by FERC. Depreciation Rates: The December 28, 2005 KCC Order authorized an annual increase in the recovery of depreciation expense of approximately $27.6 million. The approved change in depreciation rates allows for the inclusion of net salvage costs, which include an estimate for the cost of dismantlement of plant facilities. Disallowed Plant Costs: In 1985, the KCC disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in rates over the original depreciable life of Wolf Creek, or through 2025, but disallowed any return on these costs. In its December 28, 2005 order, the KCC extended the recovery period to correspond to Wolf Creek’s new estimated depreciable life. KGE recognized a loss of $10.4 million in the fourth quarter of 2005 as a result of the decrease in the present value of amounts to be received due to the extension of the recovery period. Other Regulatory Assets: The December 28, 2005 KCC Order also approved for recovery approximately $50.3 million of deferred maintenance costs associated with restoring utility service to our customers stemming from damage to our lines and equipment in the ice storms that occurred in 2002 and 2005 and various other expenses that are relatively small in relation to the total regulatory asset balance.
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Table of ContentsOPERATIONS General Westar Energy supplies electric energy at retail to approximately 355,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 305,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 48 cities in Kansas and four electric cooperatives that serve rural areas of Kansas. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we engage in energy marketing and purchase and sell wholesale electricity in areas outside our retail service territory. As discussed above, the December 28, 2005 KCC Order will allow us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power effective with the implementation of the new rates in February 2006. This applies to all fuel types we use and to our purchased power. The KCC will review our fuel and power purchasing practices on an annual basis to ensure that these expenses were incurred prudently. If it were determined that any portion of our fuel and purchased power expenses were incurred imprudently, these costs could be disallowed by the KCC. Generation Capacity We have 5,851 megawatts (MW) of generating capacity, of which 2,604 MW is owned or leased by KGE. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.
Our aggregate 2005 peak system net load of 4,549 MW occurred on July 25, 2005. Our net generating capacity, combined with firm capacity purchases and sales, provided a capacity margin of approximately 20% above system peak responsibility at the time of our 2005 peak system net load. We have agreed to provide generating capacity to other utilities as set forth below.
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Table of ContentsFossil Fuel Generation Fuel Mix The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the less fuel it takes to produce electricity. The quantity of heat consumed during the generation of electricity is measured in millions of Btu (MMBtu). Based on MMBtus, our 2005 actual fuel mix was 79% coal, 14% nuclear and 7% natural gas, oil and diesel fuel. We expect a similar fuel mix in 2006. Our fuel mix fluctuates with the operation of Wolf Creek, fluctuations in fuel costs, plant availability, customer demand and the cost and availability of power in the wholesale market. Coal Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center have an aggregate capacity of 2,210 MW, of which we own an 84% share, or 1,857 MW. We have a long-term coal supply contract with Foundation Coal West to supply coal to Jeffrey Energy Center from surface mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu delivery quantities. All of the coal used at Jeffrey Energy Center is purchased under this contract. The contract expires December 31, 2020. The contract provides for price escalation based on certain costs of production. The price for quantities purchased over the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects then current market prices. The next re-pricing is scheduled for 2008. We transport coal from Wyoming under a long-term rail transportation contract with the Burlington Northern Santa Fe (BNSF) and Union Pacific railroads. The contract term continues through December 31, 2013. The contract price is subject to price escalation based on certain costs incurred by the rail carriers. We expect increases in the cost of transporting coal due to higher prices for the items subject to contractual escalation. The average delivered cost of coal burned at Jeffrey Energy Center during 2005 was approximately $1.32 per MMBtu, or $22.01 per ton. La Cygne Generating Station: The two coal-fired units at La Cygne Generating Station (La Cygne) have an aggregate generating capacity of 1,398 MW, of which we own or lease a 50% share, or 699 MW. La Cygne unit 1 uses a blended fuel mix containing approximately 85% PRB coal and 15% Kansas/Missouri coal. La Cygne unit 2 uses PRB coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne. All of the La Cygne unit 1 and La Cygne unit 2 PRB coal is supplied through fixed price contracts through 2010 and is transported under KCPL’s Omnibus Rail Transportation Agreement with the BNSF and Kansas City Southern Railroad through December 31, 2010. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market. The La Cygne unit 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers. During 2005, the average delivered cost of all coal burned at La Cygne unit 1 was approximately $1.05 per MMBtu, or $17.91 per ton. The average delivered cost of coal burned at La Cygne unit 2 was approximately $0.88 per MMBtu, or $14.76 per ton. Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 743 MW. During 2005, we began purchasing coal under a contract with Arch Coal, Inc. This contract extends through 2009. This contract is expected to provide 100% of the coal requirement for these energy centers through 2007 and 70% of the coal requirements during 2008 and 2009. Approximately 30% of the coal to be delivered under this contract is priced within a specified range of spot market prices for 2006 and 2007 and approximately 43% of the coal to be delivered under this contract is priced within a specified range of spot market prices in 2008 and 2009. We transport coal from Wyoming using the BNSF railroad under a contract that expires in December 2006. We anticipate entering into a similar contract when the current contract expires. We expect increases in the cost of transporting coal due to higher prices.
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Table of ContentsDuring 2005, the average delivered cost of all coal burned in the Lawrence units was approximately $1.09 per MMBtu, or $19.22 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.13 per MMBtu, or $20.03 per ton. Natural Gas We use natural gas either as a primary fuel or as a start-up and/or secondary fuel, depending on market prices, at our Gordon Evans, Murray Gill, Neosho, Abilene and Hutchinson Energy Centers, in the gas turbine units at Tecumseh Energy Center and in the combined cycle units at the State Line facility. We also use natural gas as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh Energy Centers. We purchase natural gas in the spot market, which supplies our facilities with natural gas to meet our operational needs. During 2005, we purchased 7.9 million MMBtu of natural gas on the spot market for a total cost of $67.2 million. Natural gas accounted for approximately 3% of our total MMBtu of fuel burned during 2005 and approximately 16% of our total fuel expense. From time to time, we may purchase derivative contracts or use other fuel types in an effort to mitigate the effect of high natural gas prices. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” We maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. This contract expires April 30, 2006. We are currently renegotiating this contract. We meet a portion of our natural gas transportation requirements for the Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. We meet all of the natural gas transportation requirements for the State Line facility through a firm natural gas transportation agreement with Southern Star Central Pipeline. The firm transportation agreements that serve the Gordon Evans, Murray Gill, Lawrence and Tecumseh Energy Centers extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016. Oil Once started with natural gas, most of the steam units at our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn oil or natural gas. We use oil as an alternate fuel when economical or when interruptions to natural gas supply make it necessary. During 2005 oil was more economical than natural gas, therefore, we used oil as the primary fuel in these generating facilities for most of 2005. During 2005, we burned 11.5 million MMBtu of oil at a total cost of $57.3 million. Oil accounted for approximately 4% of our total MMBtu of fuel burned during 2005 and approximately 13% of our total fuel expense. From time to time, we may purchase derivative contracts or use other fuel types in an effort to mitigate the effect of high oil prices. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” Oil is also used as a start-up fuel at some of our generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase oil in the spot market and under contract. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power, to satisfy emergency requirements and to protect against reduced availability of natural gas for limited periods. Because oil does not burn as cleanly as natural gas, our ability to use as much oil in the future could be constrained by environmental regulations. See “– Environmental Matters” below for additional information.
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Table of ContentsOther Fuel Matters The table below provides the weighted average cost of fuel that we have used, including transportation costs.
Purchased Power At times, we purchase power to meet the energy needs of our customers. Factors that cause us to purchase power to serve our customers include outages at our generating plants, prices for wholesale energy, extreme weather conditions and other factors. If we were unable to generate an adequate supply of electricity to serve our customers, we would typically purchase power in the wholesale market. Transmission constraints may keep us from purchasing power in which case we would have to implement curtailment or interruption procedures as permitted by our tariffs and terms and conditions of service. Purchased power for the year ended December 31, 2005 comprised approximately 8% of our total operating expenses. The weighted average cost of purchased power was $59.05 per MWh in 2005, $54.10 per MWh in 2004 and $52.33 per MWh in 2003. Energy Marketing Activities We engage in both financial and physical trading to increase profits, manage our commodity price risk and enhance system reliability. We trade electricity, coal, natural gas and oil. We use a variety of financial instruments, including forward contracts, options and swaps, and we trade energy commodity contracts. Nuclear Generation General Wolf Creek is a 1,166 MW nuclear power plant located near Burlington, Kansas. Wolf Creek began operation in 1985. KGE owns a 47% interest in Wolf Creek, or 548 MW, which represents 9% of our total generating capacity. KCPL owns a 47% interest in Wolf Creek and a 6% interest is owned by Kansas Electric Power Cooperative, Inc. (KEPCo). The co-owners pay operating costs equal to their percentage ownership in Wolf Creek.
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Table of ContentsFuel Supply We have 100% of the uranium and conversion services needed to operate Wolf Creek through September 2009 under contract. We also have 100% of the enrichment services required to operate Wolf Creek through March 2008 under contract. Letters of intent have been issued with suppliers for a majority of Wolf Creek’s uranium, conversion and enrichment requirements extending through 2017. Fabrication requirements are under contract through 2024. All uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered into in the ordinary course of business, and we believe Wolf Creek is not substantially dependent on these agreements. However, contraction and consolidation among suppliers of these commodities and services, coupled with increasing worldwide demand and past inventory draw-downs, have introduced uncertainty as to the ability to replace, if necessary, some of these contracts in the event of a protracted supply disruption. We believe this potential problem is common in the nuclear industry. Accordingly, in the event the affected contracts were required to be replaced, we believe that the industry and government would arrive at a solution to reduce disruption of the nuclear industry’s operations. Radioactive Waste Disposal Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. Our share of the fee was $3.8 million in 2005, $4.3 million in 2004 and $3.8 million in 2003 and is calculated as one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. We include these costs in operating expenses. In 2002, the Yucca Mountain site in Nevada was approved for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. This action allows the DOE to apply to the Nuclear Regulatory Commission (NRC) to license the project. Currently, the DOE has not defined a schedule for submitting a license application. The opening of the Yucca Mountain site has been delayed many times and could be delayed further due to litigation and other issues related to the site as a permanent repository for spent nuclear fuel. Wolf Creek has on-site temporary storage for spent nuclear fuel expected to be generated by Wolf Creek through the expiration of its operating license in 2025. Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on-site facility. We believe that a temporary loss of low-level radioactive waste disposal capability would not affect Wolf Creek’s continued operation. The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Central States Compact), and the Central States Compact Commission, which is responsible for causing a new disposal facility to be developed within one of the member states. The Central States Compact Commission selected Nebraska as the host state for the disposal facility.
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Table of ContentsIn December 1998, the Nebraska agencies responsible for considering the developer’s license application denied the application. Most of the utilities that had provided the project’s pre-construction financing and the Central States Compact Commission filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the court entered a judgment of $151.4 million, about one-third of which constitutes prejudgment interest, in favor of the Central States Compact Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. Following unsuccessful appeals of the decision by Nebraska, in August 2004 Nebraska and the Central States Compact Commission settled the case. In August 2005, we received $9.2 million in proceeds from the Central States Compact as a result of the settlement. Outages Wolf Creek operates on an 18-month refueling and maintenance outage schedule. Wolf Creek was shut down for 41 days in 2005 for its fourteenth scheduled refueling and maintenance outage. During outages at the plant, we meet our electric demand primarily with our fossil-fueled generating units and by purchasing power, depending on availability and cost. As provided by the KCC, we amortize the incremental maintenance costs incurred for planned refueling outages evenly over the unit’s 18 month operating cycle. Wolf Creek is scheduled to be taken off-line in the fall of 2006 for its fifteenth refueling and maintenance outage. An extended or unscheduled shutdown of Wolf Creek could cause us to purchase replacement power, rely more heavily on our other generating units and reduce amounts of power available for us to sell at wholesale. The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on their safety significance. Wolf Creek currently meets all NRC oversight objectives and receives the minimum regimen of NRC inspections. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or other concerns. Nuclear Decommissioning Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning and dismantlement study with the KCC every three years. The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the nuclear decommissioning study, the current-year funding and future funding. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount of its pro rata share of the plant. Wolf Creek filed an updated nuclear decommissioning site study with the KCC. Based on the 2005 site study of decommissioning costs, including the costs of decontamination, dismantling and site restoration, our share of such costs are estimated to be $243.3 million. This amount compares to the 2002 site study estimate for decommissioning costs of $220.0 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment. Electric rates charged to customers provide for recovery of these nuclear decommissioning costs over the life of Wolf Creek, which, as determined by the KCC for purposes of the funding schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear decommissioning fund by the time our license expires in 2025. We believe that the KCC approved funding level will be sufficient to meet the NRC minimum financial assurance requirement. However, our consolidated results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.
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Table of ContentsNuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2005, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. The fair value approximated $100.8 million at December 31, 2005 and $91.1 million at December 31, 2004. Competition and Deregulation Electric utilities have historically operated in a rate-regulated environment. FERC, the federal regulatory agency that has jurisdiction over our wholesale rates and transmission services, and other utilities have initiated steps expected to result in a more competitive environment for utility services in the wholesale market. The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted FERC to order electric utilities to allow third parties to use their transmission systems to transport electric power to wholesale customers. In 1992, we agreed to permit third parties access to our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order encouraging the formation of regional transmission organizations (RTO). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating open and more competitive markets in bulk power. Regional Transmission Organization We are a member of the Southwest Power Pool (SPP). On October 1, 2004, FERC granted RTO status to the SPP. As a result, if approved by the KCC, we expect to transfer functional control of our transmission system to the SPP RTO under its membership agreement and applicable tariff. The SPP RTO will coordinate the operation of our transmission system within an interconnected transmission system across eight states. The SPP will collect revenues attributable to the use of each member’s transmission system. Members and transmission customers will be able to transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. We believe each transmission owner generally retains the transmission capacity needed to serve its retail customers. Any additional transmission capacity will be sold on a first come/first served non-discriminatory basis. All transmission customers will be charged uniform rates for use of the transmission system, including entities that may sell power inside our certificated service territory. We do not expect that our participation in the SPP will have a material effect on our operations; however, we expect costs to increase due to the establishment of the RTO and associated markets. At this time, we are unable to quantify these costs because market implementation issues remain unresolved. We expect that we will recover these costs in rates we charge to our customers. Real-Time Energy Imbalance Market FERC requires RTOs to establish a real-time energy imbalance market. An energy imbalance exists when a transmission market participant’s production and consumption of energy in real time does not net to zero. The intent of a real-time market system is to permit efficient balancing of production and consumption of energy and to manage congestion in real time. The SPP plans to implement a real-time energy imbalance market system on May 1, 2006. At this time, we are not able to identify the full impact on our results of operations. Regulation and Rates As a Kansas electric utility, we are subject to the jurisdiction of the KCC, which has general regulatory authority over our rates, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. Retail Rate Review As discussed above in “– Significant Business Developments During 2005 – Retail Rate Review,” our rates and cost of service were changed by the December 28, 2005 KCC Order.
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Table of ContentsFERC Proceedings Request for Change in Transmission Rates: On May 2, 2005, we filed applications with FERC that propose a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs. This is consistent with our proposals filed with the KCC on May 2, 2005 to separately charge retail customers for transmission service. These rates became effective on December 1, 2005, subject to refund. We can provide no assurance that FERC will ultimately approve our applications as filed. Market-based Rates: On March 23, 2005, FERC instituted a proceeding concerning the reasonableness of our market-based rates in our electric control area and the electrical control areas of Midwest Energy, Inc. and Aquila, Inc.’s West Plains Energy division. We have provided FERC with information it requested for its analysis. A FERC decision, anticipated in 2006, could affect how we price future wholesale power sales to wholesale customers in our control area and to Midwest Energy and West Plains Energy and wholesale customers in their control areas. We do not expect the outcome of this matter to significantly impact our consolidated results of operations. Environmental Matters General We are subject to various federal, state and local environmental laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharges of effluents into water and the use of water, and the handling and disposal of hazardous substances and wastes. These laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for our new, existing or modified facilities. If we fail to comply with such laws and regulations, we could be fined or otherwise sanctioned by regulators. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations. As discussed above, the December 28, 2005 KCC Order established the ECRR, which will allow for the timely inclusion in rates capital expenditures that are directly tied to environmental improvements required by the Clean Air Act. Environmental laws and regulations affecting power plants are overlapping, complex, subject to changes in interpretation and implementation and have tended to become more stringent over time. Although we believe that we can recover in rates the costs relating to compliance with such laws and regulations, there can be no assurance that we will be able to recover all such increased costs from our customers or that our business, consolidated financial condition or results of operations will not be materially and adversely affected as a result of costs to comply with such existing and future laws and regulations. Air Emissions The Clean Air Act, state laws and implementing regulations impose, among other things, limitations on major pollutants, including SO2, particulate matter and nitrogen oxides (NOx). Certain Kansas Department of Health and Environment (KDHE) regulations applicable to our generating facilities prohibit the emission of SO2 in excess of certain levels. In order to meet these standards, we use low-sulfur coal, fuel oil and natural gas and have equipped our generating facilities with pollution control equipment. In addition, we must comply with the provisions of the Clean Air Act Amendments of 1990 that require a two-phase reduction in some emissions. We have installed continuous monitoring and reporting equipment in order to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II SO2 and NOx requirements.
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Table of ContentsTitle IV of the Clean Air Act created an SO2 allowance and trading program as part of the federal acid rain program. Under the allowance and trading program, the Environmental Protection Agency (EPA) allocated annual SO2 emissions allowances for each affected emitting unit. An SO2 allowance is a limited authorization to emit one ton of SO2 during a calendar year. At the end of each year, each emitting unit must have enough allowances to cover its emissions for that year. Allowances are tradable so that operators of affected units that are anticipated to emit SO2 in excess of their allowances may purchase allowances from operators of affected units that are anticipated to emit SO2 in an amount less than their allowances. In 2005, we had enough emissions allowances to meet planned generation and we expect to have enough in 2006. The cost of emission allowances consumed is eligible to be recovered through the RECA. In future years, we expect to purchase SO2 allowances in order to meet the acid rain requirements of the Clean Air Act. We cannot estimate the cost at this time, but anticipate these costs may be material. The pricing of emissions allowances is unpredictable and may change over time. On March 15, 2005, the EPA issued the Clean Air Mercury Rule to permanently cap and reduce mercury emissions from coal-fired power plants. The Clean Air Mercury Rule requires reductions of mercury in two phases starting in 2010. To comply with this rule, additional controls at our coal-fired units will be required as well as the installation of additional emission monitoring equipment. Several different environmental groups and states are challenging this rule in court, which could potentially delay the implementation of this rule. To date, no part of the Clean Air Mercury Rule has been stayed by any court although court cases remain open. Assuming this rule is not stayed, the first significant compliance date for us will be the installation, certification and operation of mercury continuous emissions monitoring systems on each coal-fired unit by January 1, 2009. Based on currently available information, we cannot estimate our costs to comply with the Clean Air Mercury Rule, but these costs could be material. On March 10, 2005, in a separate but related action, the EPA issued the Clean Air Interstate Rule (CAIR) that addresses the impact of interstate transport of air pollutants on downwind states. CAIR requires reductions of SO2 and NOx in certain states in two separate phases, the first in 2010 and the second in 2015. Several states, including Kansas, are not included in the CAIR region, which reduces the impact this rule has on us. We may be required to further reduce emissions of SO2, NOx, particulate matter, mercury and carbon dioxide (CO2) as a result of various other current or pending laws, including, in particular:
Based on currently available information, we cannot estimate our costs to comply with these proposed laws, but such costs could be material. Environmental Projects KCPL began updating or installing additional equipment related to emissions controls at La Cygne unit 1 for which we incurred costs beginning in 2005. We will continue to incur costs through the completion of installation in 2009. We anticipate that our share of these costs will be approximately $105.0 million. Additionally, we have identified the potential for up to $515.0 million of expenditures at other power plants for other environmental projects during the next 8 years. This cost could increase depending on the resolution of the EPA New Source Review described below. In addition to the capital investment, were we to install such equipment, we anticipate that we would incur significant annual expense to operate and maintain the equipment and the operation of the equipment would reduce net production from our plants. As discussed above, the ECRR will allow for the timely inclusion in rates capital expenditures that are directly tied to environmental improvements required by the Clean Air Act. However, increased operating and maintenance costs can only be recovered through a change in our base rates following a rate review.
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Table of ContentsEPA New Source Review Under Section 114(a) of the Clean Air Act (Section 114), the EPA is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to New Source Review requirements or New Source Performance Standards. These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could have reasonably been expected to result in a significant net increase in emissions. The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to remove emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions. The EPA requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act. We are in discussions with the EPA concerning this matter in an attempt to reach a settlement. We expect that any settlement with the EPA could require us to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years. Additionally, we might be required to update or install emissions controls at our other coal-fired plants, pay fines or penalties, or take other remedial action. Together, these costs could be material. The EPA has informed us that it has referred this matter to the Department of Justice (DOJ) for the DOJ to consider whether to pursue an enforcement action in federal district court. We believe that costs related to updating or installing emissions controls would qualify for recovery through the ECRR. If we were to reach a settlement with the EPA, we may be assessed a penalty. The penalty could be material and may not be recovered in rates. Manufactured Gas Sites We have been associated with a number of former manufactured gas sites located in Kansas and Missouri. We and the KDHE entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the sites, our liability for twelve of the sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three sites. Our liability for our former manufactured gas sites in Missouri is limited by an environmental indemnity agreement with Southern Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our liability for these sites is capped at $7.5 million and terminates in 2009. SEASONALITY As a summer peaking utility, our sales are seasonal. The third quarter typically accounts for our highest sales volumes. The volume of sales is affected by weather conditions, the economy of our service territory and the performance of our customers. EMPLOYEES As of February 28, 2006, we had 2,191 employees. Our current contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers extends through June 30, 2008. The contract covered 1,281 employees as of February 28, 2006.
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Table of ContentsACCESS TO COMPANY INFORMATION Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge either through our Internet website at www.wr.com or by responding to requests addressed to our investor relations department. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The information contained on our Internet website is not part of this document.
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Table of ContentsEXECUTIVE OFFICERS OF THE COMPANY
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Table of ContentsITEM 1A. RISK FACTORS Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the performance of our customers. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC. Our Revenues Depend Upon Rates Determined by the KCC The KCC regulates many aspects of our business and operations, including the retail rates that we charge customers for electric service. Retail rates are set by the KCC using a cost-of-service approach that takes into account historical operating expenses, fixed obligations and recovery of capital investments. Using this approach, the KCC sets rates at a level calculated to recover such costs and a permitted return on investment. Other parties to a rate review or the KCC staff may contend that our rates are excessive. Effective January 2006, the KCC authorized changes in our rates that left our rates virtually unchanged and approved various other changes in our rate structure. The KCC also approved the RECA, which is based on the actual cost of fuel and purchased power expense less margins earned on wholesale sales, and the ECRR, which is based on capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act. Our Costs May Not be Fully Recovered in Retail Rates Once established by the KCC, our rates generally remain fixed until changed in a subsequent rate review, except to the extent the KCC permits us to modify our tariffs using interim adjustment clauses, such as the RECA and the ECRR. We may elect to file a rate review to request a change in our rates or intervening parties may request that the KCC review our rates for possible adjustment, subject to any limitations that may have been ordered by the KCC. Equipment Failures and Other External Factors Can Adversely Affect Our Results The generation and transmission of electricity requires the use of expensive and complicated equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must either produce replacement power from our less efficient units or purchase power from others at unpredictable and potentially higher cost in order to supply our customers and perform our contractual agreements. In addition, this can prevent us from having power to sell in the wholesale market. Coal deliveries from the PRB region of Wyoming, which is the primary source for our coal, have been slower than expected due primarily to problems with the rail tracks used to deliver our coal and operational problems at the mines where the coal is obtained. If rail delivery cycle times do not improve, we may be required to continue our coal conservation efforts and take other compensating measures. These measures include, but are not limited to, reducing coal consumption by revising normal dispatch of generation units, purchasing power or using more expensive power to serve customers and decreasing or, if necessary, eliminating market-based wholesale sales. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. These factors, as well as weather, interest rates, economic conditions, fuel availability, deliverability and prices, price volatility of fuel and other commodities and transportation availability and costs are largely beyond our control. Costs that are not recovered through the RECA could have a material adverse effect on our consolidated earnings, cash flows and financial position. We engage in energy marketing transactions to reduce risk from market fluctuations, enhance system reliability and increase profits. The events mentioned above could reduce our ability to participate in energy marketing opportunities, which could reduce our profits.
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Table of ContentsWe May Have Material Financial Exposure Under the Clean Air Act and Other Environmental Regulations On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements under the Clean Air Act. This notification was delivered as part of an investigation by the EPA regarding maintenance activities that have been conducted since 1980 at Jeffrey Energy Center. The EPA has informed us that it has referred this matter to the DOJ for it to consider whether to pursue an enforcement action in federal district court. The remedy for a violation could include fines and penalties and an order to install new emission control systems at Jeffrey Energy Center and at certain of our other coal-fired power plants, the associated cost of which could be material. Our activities are subject to environmental regulation by federal, state, and local governmental authorities. These regulations generally involve the use of water, discharges of effluents into the water, emissions into the air, the handling, storage and use of hazardous substances, and waste handling, remediation and disposal, among others. Congress or the State of Kansas may enact legislation and the EPA or the State of Kansas may propose new regulations or change existing regulations that could require us to reduce certain emissions at our plants. Such action could require us to install costly equipment, increase our operating expense and reduce production from our plants. The degree to which we will need to reduce emissions and the timing of when such emissions control equipment may be required is uncertain. Both the timing and the nature of required investments depend on specific outcomes that result from interpretation of regulations, new regulations, legislation, and the resolution of the EPA investigation described above. Although we expect to recover capital expenditures directly tied to environmental improvement through our rates, we can provide no assurance that we would be able to fully and timely recover all or any increased operating and maintenance costs relating to environmental compliance. Failure to recover these associated costs could have a material adverse effect on our consolidated financial condition or results of operations. Competitive Pressures from Electric Industry Deregulation Could Adversely Affect Our Revenues and Reported Earnings We currently apply the accounting principles of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business. At December 31, 2005, we had recorded $275.0 million of regulatory assets, net of regulatory liabilities. At December 31, 2004, we had recorded $334.6 million of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either as a result of the establishment of retail competition in our service territory or an expectation that permitted rates would not allow us to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. We Face Financial Risks From Our Nuclear Facility Risks of substantial liability arise from the ownership and operation of nuclear facilities, including, among others, structural problems at a nuclear facility, the storage, handling and disposal of radioactive materials, limitations on the amounts and types of insurance coverage commercially available, uncertainties with respect to the cost and technological aspects of nuclear decommissioning at the end of their useful lives and costs or measures associated with public safety. In the event of an extended or unscheduled outage at Wolf Creek, we would be required to generate power from less efficient units, purchase power in the open market to replace the power normally produced at Wolf Creek and we would have less power available for sale by us in the wholesale markets. If we were not permitted by the KCC to recover these costs, such events could have an adverse impact on our consolidated financial condition. ITEM 1B. UNRESOLVED STAFF COMMENTS None.
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Table of ContentsITEM 2. PROPERTIES
We own approximately 6,100 miles of transmission lines, approximately 23,600 miles of overhead distribution lines and approximately 3,500 miles of underground distribution lines. Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.
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Table of ContentsITEM 3. LEGAL PROCEEDINGS On September 21, 2004, a grand jury in Travis County, Texas, indicted us on charges that a $25,000 contribution by us in May 2002 to a Texas political action committee violated Texas election laws. We believe the indictment is without merit and we intend to vigorously defend against the charges. If convicted, the court could impose a fine of up to $20,000 or, in certain circumstances, in an amount not to exceed twice the amount caused to be lost by the commission of the felony. As a result of the indictment, the federal government could suspend our status as a government contractor. Upon a conviction, the federal government could bar us from acting as a government contractor. We are taking action to ensure that neither of these events occur, but we do not know whether we will be successful. We are unable to predict the ultimate impact either suspension or loss of our status as a government contractor would have on our consolidated financial position, results of operations and cash flows. Information on other legal proceedings is set forth in Notes 3, 14, 16, 17 and 18 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies – EPA New Source Review,” “Legal Proceedings,” “Ongoing Investigations” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2005. ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS STOCK TRADING Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 28, 2006, there were 27,604 common shareholders of record. For information regarding quarterly common stock price ranges for 2005 and 2004, see Note 24 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).” DIVIDENDS Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for each series. Quarterly dividends on common stock and preferred stock have historically been paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. On February 22, 2006, our board of directors declared a quarterly dividend of $0.25 per share on our common stock payable to shareholders on April 3, 2006. The indicated annual dividend rate is $1.00 per share. We expect to maintain the dividend at this level during 2006. Our articles of incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless we meet certain capitalization ratios and other conditions. We provide further information on these restrictions in Note 20 of the Notes to Consolidated Financial Statements, “Common and Preferred Stock.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock.
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Table of ContentsITEM 6. SELECTED FINANCIAL DATA
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Table of ContentsITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central United States under the regulation of the KCC and FERC. In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2005, and our operating results for the years ended December 31, 2005, 2004 and 2003. As you read Management’s Discussion and Analysis, please refer to our consolidated financial statements and the accompanying notes, which contain our operating results. SUMMARY OF SIGNIFICANT ITEMS Overview Several significant items have impacted us and our business operations since January 1, 2005.
Retail Rate Review December 28, 2005 KCC Order In accordance with a 2003 KCC order, we filed applications with the KCC on May 2, 2005 to review our rates. We requested an increase in our retail electric rates and the adoption of other practices under the KCC’s jurisdiction. While the KCC ordered a net increase in our base rates of $38.8 million annually, the increase is substantially offset by the requirement that we credit to retail customers a rolling three-year average of the margins we realize from our market-based wholesale sales. Other significant changes approved by the KCC are the RECA, the ECRR, the separation of transmission delivery charges, an increase in annual depreciation expense, an extended recovery period for costs being recovered for which no return is provided and the recovery of various costs that have been incurred and deferred as regulatory assets.
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Table of ContentsRetail Energy Cost Adjustment: The RECA allows us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power. The adjustment is based on the actual cost of fuel and purchased power less margins from market-based wholesale sales. We have contracts with certain large industrial customers, the terms of which do not provide for the separate billing of fuel costs. Fuel costs for these customers will continue to be recovered through the rates specified in each of these contracts. These customers represented approximately 8% of our total retail sales volumes for 2005. Wholesale Sales Margins: The terms of the RECA require that we include, as a credit to recoverable fuel costs, an amount based on the average of the margins realized from market-based wholesale sales during the immediately prior three-year period. In any period we are unable to realize market-based wholesale sales margins at least equal to the amount of the credit, our financial results would be adversely affected. In the short-term, our generating capacity is fixed while the load requirements of our customers change constantly. When our generating capacity is not needed to serve our customers, we attempt to seek out wholesale sales of energy at prices in excess of the costs of production. We are likely to face the prospect of decreasing margins as the energy demands of our retail customers increase, which may result in crediting to retail customers an amount that would exceed the margins realized in the current period. Environmental Cost Recovery Rider: The ECRR allows for the timely inclusion in rates, without requiring a full rate review, of the capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act. Prior to collection through rates, the KCC will review any environmental expenditures to be considered for recovery under the ECRR. Any increased operating and maintenance costs that result from updating or adding environmental equipment cannot be recovered through the ECRR. These costs would be addressed in future rate reviews. Transmission Delivery Charge: The December 28, 2005 KCC Order allows us to separate our transmission costs from our base rates charged to retail customers. This allows us to implement a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs, which provides for adjustment on a more timely basis. These rates were proposed in an application filed with FERC on May 2, 2005 and became effective on December 1, 2005, subject to refund upon review and approval by FERC. Depreciation Rates: The December 28, 2005 KCC Order authorized an annual increase in the recovery of depreciation expense of approximately $27.6 million. The approved change in depreciation rates allows for the inclusion of net salvage costs, which include an estimate for the cost of dismantlement of plant facilities. Disallowed Plant Costs: In 1985, the KCC disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in rates over the original depreciable life of Wolf Creek, or through 2025, but disallowed any return on these costs. In its December 28, 2005 order, the KCC extended the recovery period to correspond to Wolf Creek’s new estimated depreciable life. KGE recognized a loss of $10.4 million in the fourth quarter of 2005 as a result of the decrease in the present value of amounts to be received due to the extension of the recovery period. Other Regulatory Assets: The December 28, 2005 KCC Order also approved for recovery approximately $50.3 million of deferred maintenance costs associated with restoring utility service to our customers stemming from damage to our lines and equipment in the ice storms that occurred in 2002 and 2005 and various other expenses that are relatively small in relation to the total regulatory asset balance. Increasing Cost of Fuel and Purchased Power The cost of power is impacted by, among other factors, customer demand, cost and availability of fuel and purchased power, price volatility, available generation capacity and operating constraints. Higher fuel and purchased power costs, unit outages, and operating constraints, such as our efforts to conserve coal, increased our total fuel and purchased power costs.
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Table of ContentsCost of Fuel and Purchased Power: The cost of fossil fuel has increased since 2004. This is especially true for the cost of natural gas and oil. This higher cost of fuel affects not only the cost of fuel we burn, but also increases the market prices for both our wholesale sales and purchases of power. The cost and availability of fuel may cause us to use higher priced fuel types or to purchase power to meet our customers’ energy needs. The effects of the fuel price increases are reflected in our operating results. Fuel Supply Contracts: We have a net gain position on our coal supply contract for our Lawrence and Tecumseh Energy Centers. The gain position results primarily from an increase in the price of coal from the PRB region of Wyoming. Based on the terms of this contract, changes in the fair value of this contract are marked-to-market in accordance with the requirements of SFAS No. 133. As a result of the December 28, 2005 KCC Order implementing the RECA, we reversed previously recognized adjustments to fuel expense of $117.7 million related to mark-to-market adjustments and established a regulatory liability. Going forward, we will recognize changes in the fair value of fuel supply contracts as regulatory assets or liabilities. Unit Availability: Our operating results are significantly influenced by the availability of our generating units. If our more economical units are not available, we must rely on more expensive sources of power to meet our load requirements. The primary outages during the year ended December 31, 2005 were the scheduled refueling and maintenance outage and an unplanned outage at Wolf Creek and planned and unplanned outages at Jeffrey Energy Center and La Cygne. The primary outages during the year ended December 31, 2004 were the planned and unplanned outages and reduced availability of Jeffrey Energy Center. Operating Constraints: Our operating results are influenced by operating constraints on our generating units, such as coal conservation and maintenance outages. If our more economical units are constrained, we must rely on more expensive sources of power to meet our load requirements and/or forego opportunities in the wholesale power market. During the year ended December 31, 2005, coal conservation efforts, at times, reduced the energy generated at our more economical units and contributed to the decline in our market-based wholesale sales volumes. Coal conservation was required as a result of slower than expected coal deliveries, as discussed below. Coal Inventory and Delivery: Coal deliveries from the PRB region of Wyoming were slower than expected due primarily to problems with the rail tracks used to deliver our coal and operational problems at the mines where the coal is obtained. Nearly all of the coal used in our coal-fired generating stations is from the PRB region of Wyoming. During 2005, we implemented compensating measures based on delivery cycle times, our assumptions about future delivery cycle times, fuel usage and planned inventory levels. These measures included, but were not limited to, reducing coal consumption during off-peak periods by revising normal operational dispatch of our generating units, purchasing power or using more expensive power to serve customers, decreasing wholesale sales, transferring rail cars between or among our power plants and purchasing and leasing additional rail cars. These actions helped to reduce the financial impact resulting from longer delivery cycle times. The effect of the reduction in sales due to slower coal deliveries has been partially offset by higher prices received for the power we have sold in the power markets. CRITICAL ACCOUNTING ESTIMATES Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with generally accepted accounting principles (GAAP). Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or susceptibility of matters to change.
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Table of ContentsRegulatory Accounting We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with SFAS No. 71. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent probable obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the KCC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings. Pension and Post-retirement Benefit Plans Actuarial Assumptions We and Wolf Creek calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” In accounting for our retirement plans and other post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension benefit plans are impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs and employee demographics including age, compensation levels and employment periods. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the current and future periods, or on the amount of related liabilities reflected on our consolidated balance sheets or may also require cash contributions. The following table shows the annual impact of a 0.5% change in our pension plan discount rate, salary scale and rate of return on plan assets.
We recorded pension expense of approximately $12.2 million in 2005, $5.1 million in 2004 and pension income of approximately $1.0 million in 2003. Pension expense for 2006 is expected to approximate $20.4 million, which represents an $8.2 million increase over 2005. The increase is primarily due to the amortization of investment losses from prior years that are recognized on a rolling four-year average basis and changes in assumptions including a lower discount rate, lower return on assets, increase in salary scale and updated mortality tables.
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Table of ContentsThe following table shows the annual impact of a 0.5% change in our post-retirement benefit plan discount rate and rate of return on plan assets.
Revenue Recognition – Energy Sales We recognize revenues from retail energy sales upon delivery to the customer and include an estimate for energy delivered but unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured against billed sales. At December 31, 2005, we had estimated unbilled revenue of $42.1 million. We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. With the exception of fuel contracts, we include the net mark-to-market change in sales on our consolidated statements of income. We record the resulting unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. Prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results. The tables below show fair value of energy marketing contracts outstanding for the year ended December 31, 2005, their sources and maturity periods.
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Table of ContentsThe sources of the fair values of the financial instruments related to these contracts are summarized in the following table.
Income Taxes We use the asset and liability method of accounting for income taxes as required by SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties. We record deferred tax assets for capital loss, operating loss and tax credit carryforwards. However, when there are not sufficient sources of future capital gain income or taxable income to realize the benefit of the capital loss, operating loss or tax credit carryforwards, we reduce the deferred tax assets by a valuation allowance. We recognize a valuation allowance if, based on the weight of available evidence, it is considered more likely than not that some portion or all of the deferred tax asset will not be realized. We report the effect of a change in the valuation allowance in the current period tax expense. Asset Retirement Obligations We calculate our asset retirement obligations and related costs using the guidance provided by SFAS No. 143, “Accounting for Asset Retirement Obligations” and the Financial Accounting Standards Board’s (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). We estimate our asset retirement obligations based on the fair value of the asset retirement obligation we incurred at the time the related long-lived asset was either acquired, placed in service or when regulations establishing the obligation become effective. In determining our asset retirement obligations, we make assumptions regarding probable disposal costs. A change in these assumptions could have a significant impact on our asset retirement obligations reflected on our consolidated balance sheets. Contingencies and Litigation We are currently involved in certain legal proceedings and have estimated the probable cost for the resolution of these claims. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement strategies. It is possible that our future results could be materially affected by changes in our assumptions. See Note 16 of the Notes to Consolidated Financial Statements, “Legal Proceedings,” for more detailed information.
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Table of ContentsOPERATING RESULTS We evaluate operating results based on basic earnings per share. We have various classifications of sales, defined as follows: Retail: Sales of energy made to residential, commercial and industrial customers. Other retail: Sales of energy for lighting public streets and highways, net of revenues reserved for rebates. Tariff-based wholesale: Sales of energy to electric cooperatives, municipalities and other electric utilities, the rate for which is generally based on cost as prescribed by FERC tariffs. Also includes changes in valuations of contracts that have yet to settle. Market-based wholesale: Sales of energy to other wholesale customers, the rate for which is based on prevailing market prices as allowed by our FERC approved market-based tariff. Also includes changes in valuations of contracts that have yet to settle. Energy marketing: Includes: (1) market-based energy transactions unrelated to our generation or the needs of our regulated customers; (2) financially settled products and physical transactions sourced outside our control area; and (3) changes in valuations for contracts that have yet to settle that may not be recorded in tariff- or market-based wholesale revenues. Transmission: Reflects transmission revenues received, including those based on a tariff with the SPP. Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. Regulated electric utility sales are significantly impacted by such things as rate regulation, customer conservation efforts, wholesale demand, the overall economy of our service area, the weather and competitive forces. Our wholesale sales are impacted by, among other factors, demand, cost of fuel and purchased power, price volatility, available generation capacity and transmission availability. Changing weather affects the amount of electricity our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand.
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Table of Contents2005 Compared to 2004 Below we discuss our operating results for the year ended December 31, 2005 as compared to the results for the year ended December 31, 2004. Changes in results of operations are as follows.
The following table reflects changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity, for the years ended December 31, 2005 and 2004. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to electricity we generate.
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Table of ContentsResidential and commercial sales and sales volumes increased due primarily to warmer weather during 2005 than experienced in 2004. When measured by cooling degree days, the weather during 2005 was 27% warmer than during 2004 and 6% above the 20-year average. We measure cooling degree days at weather stations we believe to be generally reflective of conditions in our service territory. The warmer weather also contributed to the increased tariff-based wholesale sales and sales volumes. Additionally, about $2.7 million, or approximately 2%, of the increase in the tariff-based wholesale sales was due to the Wolf Creek outages. We sold more tariff-based wholesale power to KEPCo in accordance with a contract to supply replacement power when Wolf Creek is not available. We had more energy available from Jeffrey Energy Center, which also contributed to the increased tariff-based wholesale sales. Higher prevailing fuel prices have caused wholesale market prices to increase, which was the primary reason our market-based wholesale sales increased. Market-based wholesale sales volumes declined because less energy was available for sale due to the increase in retail and tariff-based wholesale sales. The change in energy marketing was due primarily to having more favorable changes in market valuations in 2005 compared to 2004 and due to favorable settlements of energy contracts in 2005. Fuel expense increased due primarily to using more expensive sources of generation because of the lower unit availability of our more economical generating units as discussed above in “– Summary of Significant Items – Increasing Cost of Fuel and Purchased Power – Unit Availability.” Purchased power expense increased due primarily to a 35% increase in volumes purchased during 2005 as compared to 2004. This was due to the various outages or reduced operating capability at some of our generating units and the availability of economically priced power. At times, it was more economical to purchase power than to operate our available generating units. Also contributing to the increase in purchased power expense was a 9% higher average cost. Operating and maintenance expense increased due to a number of factors, the largest of which was a $10.4 million write-off of disallowed plant costs as discussed above in “– Summary of Significant Items – Retail Rate Review – December 28, 2005 KCC Order – Disallowed Plant Costs.” In addition, costs of operating and maintaining our distribution system increased $8.4 million due primarily to higher labor costs and additional maintenance projects. Also causing the operating and maintenance expense to increase was higher taxes other than income tax of $4.7 million, a $3.5 million charge to write off plant operating system development costs at Wolf Creek due to non-performance of the vendor developing the system and higher maintenance costs at our generating units of $2.8 million due to the outages as discussed above in “– Unit Availability.” These higher expenses were partially offset by a $5.4 million decline in expense related to changes in the La Cygne unit 2 operating lease as discussed in Note 21 of the Notes to Consolidated Financial Statements, “Leases.” Depreciation expense decreased primarily because we established a regulatory asset for the depreciation differences between those used for financial statement purposes and regulatory rate making purposes from August 2001 to March 2002 pursuant to the December 28, 2005 KCC Order, which allowed us to record a reduction in depreciation expense of $20.1 million. Selling, general and administrative expenses decreased due primarily to reduced legal fees and insurance costs. Partially offsetting these decreases were increased employee pension and benefit costs. During 2004, we recognized a loss of $16.1 million in connection with the redemption of some of our senior unsecured notes and a loss of $2.7 million in connection with the redemption of the Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. Other income during 2005 was higher due primarily to $7.2 million of income from corporate-owned life insurance, which was partially offset by higher interest expense associated with borrowings on corporate-owned life insurance.
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Table of ContentsInterest expense decreased during 2005 due to lower debt balances and lower interest rates due to the refinancing activities as discussed in detail in “– Liquidity and Capital Resources” below. The increase in income tax expense reflects the increase in income from continuing operations before income taxes. 2004 Compared to 2003 Below we discuss our operating results for the year ended December 31, 2004 as compared to the results for the year ended December 31, 2003. Changes in results of operations are as follows.
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Table of ContentsThe following table reflects changes in electric sales volumes, as measured by thousands of MWh of electricity, for the years ended December 31, 2004 and 2003. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to electricity we generate.
Our retail customers used less energy and our sales decreased because of cooler weather during the summer. When measured by cooling degree days, the weather during 2004 was 12% cooler than during 2003 and 16% below the 20-year average. The accrual for rebates to be paid to customers in 2005 and 2006 pursuant to the July 25, 2003 KCC Order also reduced revenues from retail sales. During 2004, we accrued $8.5 million as compared to $3.5 million accrued during 2003. Market-based wholesale sales increased due primarily to increased sales volumes and an approximate 6% increase in the average price per MWh. As a result of milder weather, we had additional energy production available for sale at certain times during the year that was not needed to serve our retail and tariff-based wholesale customers. Increased sales volumes accounted for approximately $6.7 million of the increased market-based wholesale sales and higher average market prices accounted for approximately $7.8 million of the increase. Energy marketing sales declined because we had less favorable changes in 2004 as compared to the favorable changes in 2003 in the settlement and the fair value of positions receiving mark-to-market accounting treatment. Fuel expense increased due primarily to increases in the cost of fossil fuels, although we used approximately 2% less fuel for generation due to the lower demand caused by the cooler weather and due to unplanned outages or reduced operating capability experienced at some of our generating units at various times throughout 2004. The average equivalent availability factor for our system was 87% during 2004 compared to 90% in the prior year, due largely to the unavailability of some of our coal-fired generating units. As a result of the cooler weather and the reduced availability of our coal-fired generating units, we decreased the amount of coal burned, and consequently reduced our total expense for coal. However, the cost of natural gas and oil that we used at other generating facilities to compensate for the unplanned outages or reduced operating capability, increased our total fuel expense. Purchased power expense increased due primarily to a 34% increase in volumes purchased during 2004 as compared to 2003. At times, it was more economical to purchase power than to operate our available generating units. This was due to unplanned outages or reduced operating capability of our coal-fired generating units at certain times, and the availability of economically priced power due to cooler weather in our region. During 2003, we recorded as an offset to operating and maintenance expense a gain of $11.9 million on the sale of utility assets. The absence of a similar offset in 2004 accounted for 29% of the increase in operating and maintenance expense in 2004. The remainder of the increase was caused primarily by increased expenses associated with maintenance at Jeffrey Energy Center, increased planned and unplanned unit maintenance at various other generating units, increased maintenance of the distribution system, an increase in taxes other than income tax and an increase in the transmission costs. During 2004, increased maintenance of our generating units accounted for 23% of the increase in operating and maintenance expenses. The increase in distribution expenses accounted for 17% of the increase in operating and maintenance expenses. Distribution expenses increased due to increased staffing levels and higher costs associated with the termination of portions of the ONEOK shared services agreement as discussed in Note 22 of the Notes to Consolidated Financial Statements, “Related Party Transactions – ONEOK Shared Services Agreement.” The change in taxes other than income tax accounted for 22% of the increase in operating and maintenance expenses. An increase in transportation costs accounted for 3% of the increase in operating and maintenance expenses.
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Table of ContentsSelling, general and administrative expenses increased due primarily to an increase in legal fees, including amounts we were required to advance for fees incurred by David C. Wittig, our former president, chief executive officer and chairman, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, related to the defense of criminal charges against them, and fees associated with the pending shareholder class action and derivative lawsuits. The total other expense during 2004 was due primarily to the loss incurred on the extinguishment of debt. The total other income during 2003 was due primarily to the gain on the sale of our ONEOK stock and dividends received from ONEOK in 2003. This gain was partially offset by the loss recorded on the extinguishment of debt and the settlement of notes during 2003. Interest expense decreased in 2004 due to lower debt balances and lower interest rates due to refinancing activities as discussed below in “Liquidity and Capital Resources.” Income from discontinued operations was $78.8 million in 2004. The results recorded for 2004 include the settlement of previously pending issues as discussed in Note 23 of the Notes to Consolidated Financial Statements, “Discontinued Operations — Sale of Protection One and Protection One Europe.” This compares to a loss from discontinued operations of $77.9 million in 2003. FINANCIAL CONDITION Below we discuss significant balance sheet changes at December 31, 2005 compared to December 31, 2004. Accounts receivable increased $32.2 million due primarily to an increase in sales in late 2005 compared to late 2004. In addition, the amounts of receivables sold under our accounts receivable sales program as discussed in Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable Sales Program,” decreased $15.0 million, to $65.0 million at December 31, 2005, from $80.0 million at December 31, 2004. Inventories and supplies decreased $22.7 million due primarily to a decline in our coal inventory as discussed above in “– Summary of Significant Items – Increasing Cost of Fuel and Purchased Power – Coal Inventory and Delivery.” Net energy marketing contracts increased $111.8 million, to $117.9 million at December 31, 2005, from $6.1 million at December 31, 2004. During 2005, we realized a large increase in the net gain position on fuel supply contracts. As a result of the December 28, 2005 KCC Order granting our request for the RECA, we recognized the cumulative mark-to-market adjustment associated with our coal supply contracts as a regulatory liability of $117.7 million. For additional information on the RECA and on the mark-to-market gain on fuel supply contracts, see “– Summary of Significant Items – Retail Rate Review,” and “– Summary of Significant Items – Increasing Cost of Fuel and Purchased Power – Fuel Supply Contracts.” Our tax receivable balance declined $89.3 million primarily because we received a cash refund associated with the carry-back of our 2004 capital loss to 2003. Regulatory assets, net of regulatory liabilities, decreased to $275.0 million at December 31, 2005, from $334.6 million at December 31, 2004, due primarily to changes that resulted from the December 28, 2005 KCC Order. Total regulatory assets increased $71.9 million due primarily to an increase in debt reacquisition costs associated with the retirement and refinancing of long-term debt, maintenance costs recorded in association with an ice storm that occurred in January 2005, an increase in depreciation due to changes authorized by the December 28, 2005 KCC Order and the recording of conditional asset retirement obligations. Total regulatory liabilities increased $131.5 million due primarily to the fuel supply contracts obligation we recorded in December 2005. As discussed above, we recorded a regulatory liability of $117.7 million to recognize the cumulative mark-to-market adjustments associated with our coal supply contracts. For additional information on our regulatory assets and liabilities, see Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies – Regulatory Accounting.”
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Table of ContentsOther current assets increased $40.1 million due primarily to the recognition of the settlement of a consolidated purported class action lawsuit as discussed in detail in Note 16 of the Notes to Consolidated Financial Statements, “Legal Proceedings.” Current maturities of long-term debt increased $35.0 million. The balance at December 31, 2005 consisted of the $100.0 million outstanding aggregate principal amount of KGE 6.2% first mortgage bonds that are due in January 2006. The balance at December 31, 2004 consisted of $65.0 million outstanding aggregate principal amount of KGE 6.5% first mortgage bonds that were due in August 2005. Other current liabilities increased $41.2 million due primarily to the recognition of a receivable related to the settlement of a securities class action lawsuit as discussed in detail in Note 16 of the Notes to Consolidated Financial Statements, “Legal Proceedings.” Long-term debt, net of current maturities, decreased $76.9 million due to various financing transactions and the recognition of $100.0 million KGE 6.2% first mortgage bonds as a current maturity as discussed below in “– Liquidity and Capital Resources – Debt Financings.” Accrued employee benefits increased $38.3 million due primarily to the additional minimum pension liability recorded in 2005. For additional information, see Notes 12 and 13 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans” and “Wolf Creek Employee Benefit Plans.” Asset retirement obligations increased $42.8 million. In 2005, we determined that we have conditional asset retirement obligations that are within the scope of FIN 47 and, as a result, increased our asset retirement obligations by $21.2 million. Also during 2005, we updated our nuclear decommissioning and dismantlement study. Based upon the results of this study, we revised our estimate of our Wolf Creek asset retirement obligation and increased our liability by $14.6 million. In addition, we recorded $7.0 million in accretion expense on our asset retirement obligation related to the decommissioning of Wolf Creek. These items are discussed in greater detail in Note 15 of the Notes to Consolidated Financial Statements, “Asset Retirement Obligations.” Total other long-term liabilities decreased $15.2 million due primarily to changes in the operating lease for La Cygne unit 2 as discussed in Note 21 of the Notes to Consolidated Financial Statements, “Leases.” Accumulated other comprehensive income decreased $41.1 million due primarily to the additional minimum pension liability discussed in Notes 12 and 13 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans” and “Wolf Creek Employee Benefit Plans.” LIQUIDITY AND CAPITAL RESOURCES Overview We believe we will have sufficient cash to fund future operations, debt maturities and the payment of dividends from a combination of cash on hand, cash flows from operations and available borrowing capacity. Our available sources of funds include cash, Westar Energy’s revolving credit facility, our accounts receivable sales program and access to capital markets. Uncertainties affecting our ability to meet these cash requirements include, among others, factors affecting sales described in “Operating Results” above, economic conditions, regulatory actions, conditions in the capital markets and compliance with environmental regulations. Capital Resources At December 31, 2005, we had $38.5 million in unrestricted cash and cash equivalents. In addition, Westar Energy has a $350.0 million revolving credit facility against which $48.0 million of letters of credit have been issued, leaving $302.0 million available under this facility.
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Table of ContentsAt December 31, 2005, we also had $2.4 million of restricted cash classified as a current asset and $25.0 million of restricted cash classified as a long-term asset, primarily to provide credit security for a prepaid capacity and transmission agreement. The following table details our restricted cash at December 31, 2005.
The Westar Energy mortgage and the KGE mortgage each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. Therefore, we must ensure that we will be able to comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness. The Westar Energy mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless Westar Energy’s unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on, and 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based on the amount of bondable property additions. At December 31, 2005, based on an assumed interest rate of 6%, no additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings. The KGE mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless KGE’s net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based on the amount of bondable property additions. At December 31, 2005, based on an assumed interest rate of 6%, approximately $607.3 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage. Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million. Cash Flows from Operating Activities Cash flows from operating activities increased $8.3 million to $353.9 million in 2005 from $345.6 million in 2004. During 2005, we used approximately $33.1 million for system restoration costs related to the ice storm that affected our service territory in January 2005, and approximately $14.2 million for the Wolf Creek refueling outage. We also used cash for increases in fuel and purchased power costs. During 2005, we received approximately $47.5 million more in tax refunds than we did during 2004. Cash paid for interest was $40.4 million lower in 2005 than in 2004 due primarily to our lower debt balances. Cash flows from operating activities increased $197.1 million to $345.6 million in 2004 from $148.5 million for 2003. This increase was primarily attributable to reduced interest of $80.2 million and reduced tax payments of $52.5 million. Cash Flows (used in) from Investing Activities In general, cash used for investing purposes relates to the growth and improvement of our electric utility business. The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $212.8 million in 2005, $197.1 million in 2004 and $163.3 million in 2003 on net additions to utility property, plant and equipment.
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Table of ContentsIn 2004, we received net proceeds of $108.3 million from the sale of Protection One and Protection One bonds. During 2003, we received net proceeds of $801.8 million from the sale of ONEOK stock and net proceeds of $33.3 million from the sale of utility assets. Cash Flows used in Financing Activities Financing activities in 2005 used $127.9 million of cash compared to $323.2 million in 2004. In 2005, we received cash primarily from the issuance of long-term debt and we used cash primarily to retire long-term debt and pay dividends. Financing activities in 2004 used $323.2 million of cash compared to $881.1 million in 2003. In 2004, we received cash from issuances of long-term debt and the issuance of common stock, and cash was used for the retirement of long-term debt and payment of dividends. In 2003, cash was used in financing activities for the retirement of long-term debt and the payment of dividends. In 2003, we reduced our indicated annual dividend from $1.20 per share to $0.76 per share. Future Cash Requirements Our business requires significant capital investments. Through 2008, we expect we will need cash mostly for utility construction programs designed to improve facilities providing electric service, for future peaking capacity needs and to comply with environmental regulations. We anticipate that additional cash expenditures will be necessary to purchase and build additional peaking generation capacity that we anticipate will be needed in 2008. We expect to meet these cash needs with internally generated cash flow, borrowings under Westar Energy’s revolving credit facility and through the issuance of securities in the capital markets. If we are required to update emissions controls or take other remedial action as a result of the EPA’s investigation, the costs could be material. We may also have to pay fines or penalties or make significant capital or operational expenditures related to the notice of violation we received from the EPA in connection with certain projects completed at Jeffrey Energy Center. In addition, significant capital or operational expenditures may be required in order to comply with future environmental regulations or in connection with future remedial obligations. The following table does not include any amounts related to these possible expenditures. We expect that costs related to updating or installing emissions controls will be material. As discussed above, the ECRR will allow for timely inclusion in rates of the costs of capital expenditures directly tied to environmental improvements required by the Clean Air Act. We believe that other costs incurred would qualify for recovery through rates. Capital expenditures for 2005 and anticipated capital expenditures for 2006 through 2008, including costs of removal, are shown in the following table.
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Table of ContentsWe prepare these estimates for planning purposes and revise our estimates from time to time. Actual expenditures will differ from our estimates. These amounts do not include any estimate of expenditures that may be incurred as a result of the EPA investigation. Maturities of long-term debt at December 31, 2005 are as follows.
Debt Financings On January 17, 2006, KGE repaid the outstanding $100.0 million aggregate principal amount of KGE 6.2% first mortgage bonds with cash on hand and borrowings under the Westar Energy revolving credit facility. On August 1, 2005, KGE repaid the outstanding $65.0 million aggregate principal amount of KGE 6.5% first mortgage bonds with cash on hand and borrowings under the Westar Energy revolving credit facility. On June 30, 2005, Westar Energy sold $400.0 million aggregate principal amount of Westar Energy first mortgage bonds, consisting of $150.0 million of 5.875% bonds maturing in 2036 and $250.0 million of 5.1% bonds maturing in 2020. On July 27, 2005, proceeds from the offering were used to redeem the outstanding $365.0 million aggregate principal amount of Westar Energy’s 7.875% first mortgage bonds due 2007, together with accrued interest and a call premium equal to approximately 6% of the principal outstanding, and for general corporate purposes. The call premium is recorded as a regulatory asset and is being amortized over the term of the new bonds. On May 6, 2005, Westar Energy amended its revolving credit facility dated March 12, 2004 to extend the term and reduce borrowing costs. The amended revolving credit facility matures on May 6, 2010. The facility is used as a source of short-term liquidity. It allows us to borrow up to an aggregate amount of $350.0 million, including letters of credit up to a maximum aggregate amount of $100.0 million. So long as there is no default or event of default under the revolving credit facility, Westar Energy may elect, subject to lender participation, to increase the aggregate amount of borrowings under this facility to $500.0 million. All borrowings under the revolving credit facility are secured by KGE first mortgage bonds. At December 31, 2005, we had no outstanding borrowings and $48.0 million of letters of credit outstanding under this facility. A default by Westar Energy or KGE under other indebtedness totaling more than $25.0 million is a default under this facility. Westar Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio not greater than 65% at all times. Available liquidity under the facility is not impacted by a decline in Westar Energy’s credit ratings. Also, the facility does not contain a material adverse effect clause requiring Westar Energy to represent, prior to each borrowing, that no event resulting in a material adverse effect has occurred. On January 18, 2005, Westar Energy sold $250.0 million aggregate principal amount of Westar Energy first mortgage bonds, consisting of $125.0 million 5.15% bonds maturing in 2017 and $125.0 million 5.95% bonds maturing in 2035. On February 17, 2005, we used the net proceeds from the offering, together with cash on hand, additional funds raised through the accounts receivable conduit facility and borrowings under Westar Energy’s revolving credit facility, to redeem the remaining $260.0 million aggregate principal amount of Westar Energy 9.75% senior notes due 2007. Together with accrued interest and a premium equal to approximately 12% of the outstanding senior notes, we paid $298.5 million to redeem the Westar Energy 9.75% senior notes due 2007. The call premium is recorded as a regulatory asset and is being amortized over the term of the new bonds.
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Table of ContentsOn June 10, 2004, KGE refinanced $327.5 million of pollution control bonds. The original issue had an interest rate of 7% and was due in 2031. This issue was replaced with pollution control bonds at interest rates of 5.3% on $127.5 million that matures in 2031, 2.65% on $100.0 million that matures in 2031, and a variable rate on $100.0 million that matures in 2031. Debt Covenants Some of our debt instruments contain restrictions that require us to maintain leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. These ratios are used solely to determine compliance with our various debt covenants. We were in compliance with these covenants at December 31, 2005. Affiliate Long-Term Debt and Other Mandatorily Redeemable Securities On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. On April 16, 2004, we redeemed our entire issuance of Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, at par. On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B. On September 22, 2003, we redeemed our entire issuance of Western Resources Capital II 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, at par. Interest Rate Swap Effective October 4, 2001, we entered into a $500.0 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on a term loan at 6.18%. We settled the swap agreement for a nominal amount on September 29, 2003. For information regarding ongoing interest rates, see Note 10, of the Notes to Consolidated Financial Statements, “Long-Term Debt.” Credit Ratings Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service (Moody’s) and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our securities. On January 30, 2006, Moody’s lowered our speculative grade liquidity rating to SGL-2 (good) from SGL-1 (very good). On February 23, 2005, Moody’s upgraded its ratings for our debt. Secured debt ratings for us and KGE were upgraded to Baa3 from Ba1. Our unsecured ratings were upgraded to Ba1 from Ba2. On December 22, 2004, Fitch raised its outlook for our ratings to positive from stable and affirmed its ratings as shown in the table below. On July 22, 2004, S&P improved its ratings on KGE’s first mortgage bonds to BBB from BB+. As of March 1, 2006, ratings with these agencies are as shown in the table below.
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Table of ContentsIn general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us. Westar Energy and KGE have credit rating conditions under our revolving credit agreement and in the agreements governing the sale of our accounts receivable discussed in Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable Sales Program,” that affect the cost of borrowing but do not trigger a default. We may enter into new credit agreements that contain credit conditions, which could affect our liquidity and/or our borrowing costs. Capital Structure At December 31, 2005 and 2004, our capital structure consisted of 45% common equity, 1% preferred stock and 54% long-term debt. OFF-BALANCE SHEET ARRANGEMENTS At December 31, 2005, we did not have any off-balance sheet financing arrangements, other than our accounts receivable sales program and operating leases entered into in the ordinary course of business. Accounts Receivable Sales Program Under a revolving accounts receivable sales program, we can currently sell up to $125.0 million of our accounts receivable. For additional detail, see Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable Sales Program.” CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS In the course of our business activities, we enter into a variety of obligations and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements. The obligations listed below do not include amounts for on-going needs for which no contractual obligations existed at December 31, 2005. We may from time to time enter into new contracts to replace contracts that expire.
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Table of ContentsContractual Cash Obligations The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2005.
Commercial Commitments Our commercial commitments existing at December 31, 2005 consist of outstanding letters of credit that expire in 2006. The letters of credit are comprised of $38.8 million related to our energy marketing and trading activities, $4.3 million related to worker’s compensation and $5.3 million related to other operating activities for a total outstanding balance of $48.4 million. OTHER INFORMATION Agreement to Purchase Electric Generation Facility On October 21, 2005, we entered into an agreement to purchase a 300 MW electric generation facility from ONEOK Energy Services Company, L.P. for $53.0 million. The agreement also requires us to assume a capacity sale agreement with the Oklahoma Municipal Power Authority for 75 MW through 2015. The transaction is subject to a number of conditions, including FERC approval. We expect the transaction to close in 2006. Sale of Utility Assets In August 2003, we sold a portion of our transmission and distribution assets and rights to provide service to approximately 10,000 customers in an area of central Kansas. Total sales proceeds received were $33.3 million and we realized a gain of $11.9 million.
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Table of ContentsPayment of Rebates On July 25, 2003, the KCC issued an order approving a Stipulation and Agreement, the principal terms of which included a requirement for us to pay customer rebates of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. The first rebate appeared as credits on customers’ billing statements in May and June of 2005. The second rebate appeared as credits on customers’ billing statements in January of 2006. Impact of Regulatory Accounting We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our electric utility operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings. At December 31, 2005, we had recorded regulatory assets currently subject to recovery in future rates of approximately $437.5 million and regulatory liabilities of $162.5 million as discussed in greater detail in Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies – Regulatory Accounting.” We believe that it is probable that our regulatory assets will be recovered in the future. Asset Retirement Obligations In accordance with SFAS No. 143, adopted January 2003, and FIN 47, adopted December 31, 2005, we have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Legal Liability On January 1, 2003, we recognized the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the fair value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. During 2005 we updated our nuclear decommissioning and dismantlement study. Based on the results of the 2005 study, we have revised our estimate of our Wolf Creek asset retirement obligation. Accordingly, in 2005 we increased our asset retirement liability $14.6 million. Costs to retire Wolf Creek are currently being recovered through rates as provided by the KCC. During 2005 we determined that we have conditional asset retirement obligations that are within the scope of FIN 47. The conditional asset retirement obligations include disposal of asbestos insulating material at our power plants, remediation of ash disposal ponds and the disposal of polychlorinated biphenyl (PCB) contaminated oil. As of December 31, 2005, we recorded an asset retirement obligation of approximately $21.2 million pursuant to the requirements of FIN 47 based on the fair value of these disposal obligations. The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the Environmental Protection Agency published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.” We also capitalized the retirement obligation as an increase to the asset’s carrying value. The amount of the asset retirement obligation related to asbestos disposal was $9.3 million at December 31, 2005. We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. We have determined that the closure of these facilities represents a conditional asset retirement obligation as defined by FIN 47. Accordingly, we have recognized an asset retirement obligation for the ash landfills. The liability was determined based upon the date each landfill was originally placed in service. The amount of the asset retirement obligation related to remediation of ash disposal ponds was $10.9 million at December 31, 2005.
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Table of ContentsPCB contaminates are contained within company electrical equipment, primarily transformers. We have determined that the disposal of PCB-contaminated equipment represents a conditional asset retirement obligation as defined by FIN 47. Accordingly, we have recognized an asset retirement obligation for the PCB-contaminated equipment. The liability was determined based upon the PCB regulations that originally became effective in 1978. The amount of the asset retirement obligation related to the disposal of PCB contaminated oil was $1.0 million at December 31, 2005. For additional information on our legal asset retirement obligations, see Note 15 of the Notes to Consolidated Financial Statements, “Asset Retirement Obligations.” Non-Legal Liability – Cost of Removal We recover in rates, as a component of depreciation, the costs to dispose of utility plant assets that do not represent legal retirement obligations. At December 31, 2005 and 2004, Westar Energy had incurred, but had not recovered, $0.3 million and $1.3 million, respectively, in removal costs, which were classified as a regulatory asset. At December 31, 2005 and 2004, KGE had $6.9 million and $2.6 million, respectively, in amounts collected, but unspent, for removal costs classified as a regulatory liability. The net amount related to non-legal retirement costs can fluctuate based on amounts recovered in rates compared to removal costs incurred. Guardian International Preferred Stock On March 6, 2006, Guardian International, Inc. (Guardian) was acquired by Devcon International Corporation in a merger. In connection with this merger, we received approximately $23.2 million for 15,214 shares of Guardian Series D preferred stock and 8,000 shares of Guardian Series E preferred stock held of record by us. We beneficially owned 354.4 shares of the Guardian Series D preferred stock and 312.9 shares of the Guardian Series E preferred stock. We will record a gain in 2006 of approximately $0.3 million as a result of the payment for these shares. Certain current and former officers beneficially owned the remaining shares. Of these shares, 14,094 shares of Guardian Series D preferred stock and 7,276 shares of Guardian Series E preferred stock were beneficially owned by Mr. Wittig and Mr. Lake. The ownership of the shares beneficially owned by Mr. Wittig and Mr. Lake, as well as related dividends, is disputed and is the subject of the arbitration proceeding with Mr. Wittig and Mr. Lake discussed in Note 16 of the Notes to Consolidated Financial Statements, “Legal Proceedings.” These shares were also part of the property forfeited by Mr. Wittig and Mr. Lake in the criminal proceeding discussed in Note 18 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake.” As a result of this transaction, we no longer hold any Guardian securities. New Accounting Pronouncements Share-Based Payment: In December 2004, FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R requires companies to recognize as compensation expense the grant-date fair value of stock options and other equity-based compensation issued to employees. We implemented the provisions of the statement on January 1, 2006. We currently use RSUs for stock-based awards granted to employees. Given the characteristics of our stock-based compensation program, we do not expect the adoption of SFAS No. 123R to materially impact our consolidated results of operations. Accounting Changes and Error Corrections: On May 30, 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – Replacement of APB 20 and SFAS No. 3,” which changes the requirements for the accounting and reporting of a change in accounting principle. SFAS No. 154 applies to all voluntary changes in accounting principle as well as to changes required by an accounting pronouncement that does not include specific transition provisions. For most accounting changes and error corrections, SFAS No. 154 requires retrospective application, under which the new accounting principle is applied as of the beginning of the first period presented as if that principle had always been used. SFAS No. 154 is effective for accounting changes and corrections of errors made beginning January 1, 2006. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Hedging Activity We may use derivative financial and physical instruments to economically hedge the price of a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine what the value will be when the agreements are actually settled. In an effort to mitigate market risk associated with fuel and energy prices, we may use economic hedging arrangements to reduce our exposure to price changes. Our future exposure to changes in prices will be dependent on the market prices and the extent and effectiveness of any economic hedging arrangements into which we enter. See Note 5 of the Notes to Consolidated Financial Statements, “Financial Instruments, Energy Marketing and Risk Management — Derivative Instruments and Hedge Accounting — Hedging Activities,” for detailed information regarding hedging relationships and an interest rate swap we entered into during the third quarter of 2001.
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Table of ContentsMarket Price Risks Our economic hedging and trading activities involve risks, including commodity price risk, interest rate risk and credit risk. Commodity price risk is the risk that changes in commodity prices may impact the price at which we are able to buy and sell electricity and purchase fuels for our generating units. We believe we will continue to experience volatility in the prices for these commodities. Interest rate risk represents the risk of loss associated with movements in market interest rates. In the future, we may use swaps or other financial instruments to manage interest rate risk. Credit risk represents the risk of loss resulting from non-performance by a counterparty of its contractual obligations. We have exposure to credit risk and counterparty default risk with our retail, wholesale and energy marketing activities. We maintain credit policies intended to reduce overall credit risk. We employ additional credit risk control mechanisms that we believe are appropriate, such as letters of credit, parental guarantees and master netting agreements with counterparties that allow for offsetting exposures. Results actually achieved from economic hedging and trading activities could vary materially from intended results and could materially affect our consolidated financial results depending on the success of our credit risk management efforts. Commodity Price Exposure We may engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil. We use a variety of financial instruments, including forward contracts, options and swaps, and we trade energy commodity contracts. We may also use economic hedging techniques to manage overall fuel expenditures. We procure physical products under forward agreements and spot market transactions. We are involved in trading activities to reduce risk from market fluctuations, enhance system reliability and increase profits. Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations. Our risk of loss, in the form of increased costs, from market price changes in fuel is mitigated through the RECA, which provides for inclusion of most fuel costs in retail rates. We manage and measure the market price risk exposure of our trading portfolio using a variance/covariance value-at-risk (VaR) model. The VaR model is designed to measure the predicted maximum one-day loss at a 95% confidence level. In addition to VaR, we employ additional risk control processes such as stress testing, daily loss limits, credit limits and position limits. We expect to use similar control processes in 2006. The use of the VaR method requires assumptions, including the selection of a confidence level for potential losses and the estimated holding period. We are also exposed to the risk that we value and mark illiquid prices incorrectly. We express VaR as a potential dollar loss based on a 95% confidence level using a one-day holding period. The calculation includes derivative commodity instruments used for both trading and risk management purposes. The VaR amounts for 2005 and 2004 were as follows.
We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that we believe are effective in managing overall credit risk. There can be no assurance that the employment of VaR, or other risk management tools we employ, will eliminate the possibility of a loss.
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Table of ContentsWe are also exposed to commodity price changes outside of trading activities. We use derivative contracts for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service. The loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition. Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of fossil fuel used for generation vary from year to year based on availability, price and deliverability of a given fuel type as well as planned and scheduled outages at our facilities that use fossil fuels and the nuclear refueling schedule. Our customers’ electricity usage could also vary from year to year based on the weather or other factors. Interest Rate Exposure We have entered into various fixed and variable rate debt obligations. For details, see Note 10 of the Notes to Consolidated Financial Statements, “Long-Term Debt.” Sensitivity to changes in interest rates for variable rate debt and current maturities of fixed rate debt is computed by assuming a 100 basis point change in the current interest rate applicable to such debt over the remaining time the debt is outstanding. We had approximately $321.9 million of variable rate debt and current maturities of fixed rate debt at December 31, 2005. A 100 basis point change in interest rates applicable to this debt would impact operating income on an annualized basis by approximately $2.3 million. Security Price Risk We maintain trust funds, as required by the NRC and Kansas state laws, to fund certain costs of nuclear plant decommissioning. As of December 31, 2005, these funds were comprised of 66% domestic equity securities, 24% debt securities and 10% cash and cash equivalents. The fair value of these funds was $100.8 million as of December 31, 2005 and $91.1 million as of December 31, 2004. By maintaining a portfolio that includes long-term equity investments, we seek to maximize the returns to be utilized to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the portfolio by benchmarking the performance of the investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trusts to various investment options. Our exposure to equity price market risk is, in large part, mitigated, due to the fact that we are currently allowed to recover decommissioning costs in our electric rates, which would include unfavorable investment results.
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Table of ContentsITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included on our consolidated financial statements and schedules presented: I, III, IV, and V.
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Table of ContentsMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING We are responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers 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 and includes those policies and procedures that:
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. We assessed the effectiveness of our internal control over financial reporting at December 31, 2005. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on the assessment, we believe that, at December 31, 2005, our internal control over financial reporting is effective based on those criteria. Our independent registered public accounting firm has issued an audit report on our assessment of our internal control over financial reporting.
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Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Westar Energy, Inc. Topeka, Kansas We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Westar Energy, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, 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, 2005, 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, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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Table of ContentsWe have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2005 of the Company and our report dated March 10, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding revisions made to the consolidated statements of cash flows for the years ended December 31, 2004 and 2003. /s/ Deloitte & Touche LLP Kansas City, Missouri March 10, 2006
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Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Westar Energy, Inc. Topeka, Kansas We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. 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 misstatement. 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, such consolidated financial statements present fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. In 2005, the Company changed the presentation of its consolidated statements of cash flows to present separate disclosure of the cash flows from operating, investing, and financing activities of discontinued operations and other matters, as discussed in Note 2 and retroactively revised the consolidated statements of cash flows for the years ended December 31, 2004 and 2003, for the change. 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, 2005, 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 10, 2006 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. /s/ Deloitte & Touche LLP Kansas City, Missouri March 10, 2006
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Table of ContentsCONSOLIDATED BALANCE SHEETS (Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Dollars in Thousands)
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