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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to _________ Commission File Number 1-7324 KANSAS GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Kansas 48-1093840 ------ ---------- (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification Number) P.O. BOX 208 Wichita, Kansas 67201 (316) 261-6611 (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: None Securities registered pursuant to section 12(g) of the Act: None 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 the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class Outstanding at March 14, 2002 ----- ----------------------------- Common Stock, No par value 1,000 Shares Registrant meets the conditions of General Instruction I(1)(a) and (b) to Form 10-K for certain wholly-owned subsidiaries and is therefore filing an abbreviated form. Documents Incorporated by Reference: None
TABLE OF CONTENTS Page ---- PART I Item 1. Business........................................................................... 4 Item 2. Properties......................................................................... 16 Item 3. Legal Proceedings.................................................................. 17 Item 4. Submission of Matters to a Vote of Security Holders................................ 17 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.............. 17 Item 6. Selected Financial Data............................................................ 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ..................................................................... 18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................... 34 Item 8. Financial Statements and Supplementary Data........................................ 35 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........................................................................ 61 PART III Item 10. Directors and Executive Officers of the Registrant................................. 61 Item 11. Executive Compensation............................................................. 61 Item 12. Security Ownership of Certain Beneficial Owners and Management..................... 61 Item 13. Certain Relationships and Related Transactions..................................... 61 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................... 62 Signatures................................................................................... 65 2
FORWARD-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," "expect," "plan," "will," "may," "could," "estimate," "intend" or words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning: . capital expenditures, . earnings, . liquidity and capital resources, . litigation, . possible corporate restructurings, mergers, acquisitions, dispositions, . compliance with debt and other restrictive covenants, . interest and dividends, . the financial condition of other Western Resources, Inc.'s subsidiaries and their impact on Western Resources, Inc.'s results, including impairment charges that may affect our liquidity, . environmental matters, . nuclear operations, and . the overall economy of our service area. What happens in each case could vary materially from what we expect because of such things as: . electric utility deregulation, . ongoing municipal, state and federal activities, such as the Wichita municipalization effort, . future economic conditions, . changes in accounting requirements and other accounting matters, . changing weather, . rate and other regulatory matters, including the impact of the order to reduce our rates issued on July 25, 2001 by the Kansas Corporation Commission and the impact of the Kansas Corporation Commission's order issued July 20, 2001 and related proceedings, with respect to the proposed separation of Western Resources, Inc.'s electric utility businesses (including us) from Westar Industries, Inc., . the impact on our service territory of the September 11, 2001 terrorist attacks, . the impact, if any, of Enron Corp.'s bankruptcy on the market for trading wholesale electricity, . political, legislative and regulatory developments, . amendments or revisions to Western Resources, Inc.'s current plans, . the consummation of the acquisition of the electric operations of Western Resources, Inc. (including us) by Public Service Company of New Mexico and related litigation, . regulatory, legislative and judicial actions, . regulated and competitive markets, and . other circumstances affecting anticipated operations, sales and costs. These lists are not all-inclusive because it is not possible to predict all possible factors. See "Item 1. Business -- Risk Factors" for additional information on matters that could impact our expectations. Any forward-looking statement speaks only as of the date such statement was made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made. 3
PART I ITEM 1. BUSINESS GENERAL Kansas Gas and Electric Company (KGE, the company, we, us or our) is a rate-regulated electric utility and wholly owned subsidiary of Western Resources, Inc. (Western Resources). We provide rate-regulated electric service, together with the electric utility operations of Western Resources, using the name Westar Energy. We are engaged principally in the generation, purchase, transmission, distribution and sale of electricity in southeastern Kansas, including the Wichita metropolitan area. Our corporate headquarters are located in Wichita, Kansas. We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). We record our proportionate share of all transactions of WCNOC as we do other jointly owned facilities. SIGNIFICANT BUSINESS DEVELOPMENTS PNM Transaction On November 8, 2000, Western Resources entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire Western Resources' electric utility businesses (including us) in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and Western Resources are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. At the same time Western Resources entered into the agreement with PNM, Western Resources and Westar Industries, a wholly owned subsidiary of Western Resources, entered into an Asset Allocation and Separation Agreement, which, among other things, provided for a split-off of Westar Industries and related matters. On October 12, 2001, PNM filed a lawsuit against Western Resources in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for Western Resources' electric utility businesses. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, Western Resources filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of Western Resources' electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, Western Resources filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to Western Resources purporting to terminate the merger in accordance with the terms of the merger agreement. Western Resources has notified PNM that it believes the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. Western Resources intends to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, Western Resources believes the closing of the proposed merger is not likely. KCC Rate Cases On November 27, 2000, Western Resources and we filed applications with the KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC issued orders that reduced our electric rates by $41.2 million. 4
Western Resources and we appealed these orders to the Kansas Court of Appeals, but the KCC orders were upheld. We are evaluating whether to appeal the decision to the Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summary of Significant Items - - KCC Rate Cases" for further discussion. KCC Proceedings and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of Western Resources' electric utility businesses (including us) from its non-utility businesses, including the rights offering, and other aspects of its unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving Western Resources' unregulated businesses are consistent with its obligation to provide efficient and sufficient electric service at just and reasonable rates to its electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement Western Resources entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by Western Resources to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by Western Resources' unregulated businesses and whether they should continue to be affiliated with its electric utility business, and Western Resources' present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Western Resources from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting Western Resources and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed Western Resources and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in Western Resources' capital structure applicable to its electric utility operations, which has the effect of prohibiting it from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed Western Resources to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of its non-utility businesses. In its order, the KCC also acknowledged that Western Resources and we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. Western Resources appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that Western Resources and the KCC staff make filings addressing whether the filing of applications by Western Resources and us at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that Western Resources not increase the share of debt in its capital structure applicable to its electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC staff filed a motion to intervene in the proceeding at FERC asserting the same position. Western Resources is unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing Western Resources' and our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on Western Resources' or our ability to refinance indebtedness maturing in the next several years. Western Resources' or our inability to refinance existing indebtedness on a secured basis would likely increase borrowing costs and adversely affect Western Resources' and our results of operations. 5
The Financial Plan The July 20, 2001 KCC order directed Western Resources to present a financial plan to the KCC. Western Resources presented a financial plan to the KCC on November 6, 2001, which it amended on January 29, 2002. The principal objective of the financial plan is to reduce Western Resources' total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that Western Resources will proceed with the rights offering and that, in the event that the PNM merger and related split-off do not close, Western Resources will use its best efforts to sell its share of Westar Industries common stock, or shares of its common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. Western Resources is unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take. Ice Storm In late January 2002, a severe ice storm swept through our service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs to be approximately $13 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. ELECTRIC UTILITY OPERATIONS General We supply electric energy at retail to approximately 293,000 customers in Kansas. We also supply electric energy at wholesale to the electric distribution systems of 27 Kansas cities. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. Our electric sales for the years ended December 31, 2001, 2000 and 1999 were as follows: 2001 2000 1999 -------- -------- -------- (In Thousands) Residential .................... $222,427 $246,665 $220,645 Commercial ..................... 175,899 175,686 169,427 Industrial ..................... 155,990 161,693 163,158 Wholesale ...................... 77,762 78,596 63,255 System Marketing ............... 16,077 17,660 -- Other .......................... 24,970 23,690 21,855 -------- -------- -------- Total ...................... $673,125 $703,990 $638,340 ======== ======== ======== The following table reflects electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No sales volumes are included for system marketing sales, because these sales are not based on electricity we generate. 2001 2000 1999 ------ ------ ------ (Thousands of MWh) Residential .................... 2,734 2,950 2,601 Commercial ..................... 2,632 2,544 2,413 Industrial ..................... 3,488 3,561 3,548 Wholesale ...................... 2,479 2,407 1,832 Other .......................... 44 45 45 ------ ------ ------ Total ...................... 11,377 11,507 10,439 ====== ====== ====== 6
Generation Capacity The aggregate net generating capacity of our system is presently 2,616 megawatts (MW). The system has interests in 12 fossil-fuel steam generating units, one nuclear generating unit (47% interest), one diesel generator and two wind generators. Our aggregate 2001 peak system net load of 2,076 MW occurred on July 30, 2001. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 18% above system peak responsibility at the time of the peak. Our all time peak system net load of 2,111 MW occurred on August 11, 1999. We have a market-based rate authority from the FERC, under which we buy and sell energy and capacity throughout the United States. We are a member of the Southwest Power Pool (SPP). In February 2002, SPP and the Midwest Independent System Operator, Inc. (MISO) executed a definitive agreement for the consolidation of the two organizations, which is expected to occur in 2003. We anticipate that after the consolidation of SPP and MISO, we will participate in MISO. Among other things, these organizations were formed to maintain transmission system reliability on a regional basis. See "- Competition and Deregulation" below for more information on these organizations. We are also a member of the SPP transmission tariff, along with ten other transmission providers in the region. Revenues from this tariff are divided among the tariff members based upon calculated impacts to their respective systems. The tariff allows for both firm and non-firm transmission access. We will file a new transmission tariff with MISO as it becomes operational. We have an agreement with Midwest Energy, Inc. to provide it with peaking capacity of 60 MW through May 2008. We forecast that we will need additional generating capacity of approximately 150 MW by 2006 to serve our customers' expected electricity needs. We will determine how to meet this need at a future date. Fossil Fuel Generation Fuel Mix: Coal-fired units comprise 1,124 MW of our total 2,616 MW of generating capacity and the nuclear unit provides 550 MW of capacity. Of the remaining 942 MW of generating capacity, units that can burn either natural gas or oil account for 942 MW, one unit that burns only diesel fuel accounts for 3 MW, and wind turbines account for approximately 0.4 MW (see "Item 2. Properties"). Based on MMBtus burned, the 2001 and estimated 2002 fuel mix (percent of electricity produced by a specific fuel type) are as follows: Estimated Fuel 2001 2002 ---- ---- ---- Coal.......................... 54% 58% Nuclear....................... 37% 31% Gas, Oil or Diesel Fuel....... 9% 11% Our fuel mix fluctuates with the operation of the nuclear-powered Wolf Creek (as discussed below under "-- Nuclear Generation"), fuel costs, plant availability and power available on the wholesale market. 7
Coal: Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 443 MW (our 20% share). Western Resources, the operator of JEC, and we have a long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company, to supply coal to JEC from mines located in the Powder River Basin in Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual MMBtu delivery quantities. The coal supplied is surface mined and had an average Btu content of approximately 8,407 Btu per pound and an average sulfur content of .43 lbs/MMBtu (see "-- Environmental Matters"). The average cost of coal burned at JEC during 2001 was approximately $1.10 per MMBtu, or $18.57 per ton. Coal is transported from Wyoming under a long-term rail transportation contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP) railroads with a term continuing through December 31, 2013. LaCygne Generating Station: The two coal-fired units at LaCygne Station have an aggregate generating capacity of 681 MW (KGE's 50% share). LaCygne 1 uses a blended fuel mix containing approximately 85% Powder River Basin coal and 15% Kansas/Missouri coal. LaCygne 2 uses Powder River Basin coal. The operator of LaCygne Station, Kansas City Power and Light Company (KCPL), administers the coal and coal transportation contracts. A portion of the LaCygne 1 and LaCygne 2 Powder River Basin coal is supplied through several fixed price and spot market contracts that expire at various times through 2003 and is transported under KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern Railroad through December 31, 2010. Additional coal may be acquired on the spot market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers. The Powder River Basin coal supplied during 2001 had an average Btu content of approximately 8,527 Btu per pound and an average sulfur content of .73 lbs/MMBtu. During 2001, the average cost of all coal burned at LaCygne 1 was approximately $0.86 per MMBtu, or $14.88 per ton. The average cost of coal burned at LaCygne 2 was approximately $0.79 per MMBtu, or $13.47 per ton. General: We have entered into all of our coal contracts in the ordinary course of business and do not believe we are substantially dependent upon these contracts. We believe there are other suppliers with plentiful sources of coal available at spot market prices to replace, if necessary, fuel to be supplied pursuant to these contracts. In the event that we were required to replace our coal agreements, we would not anticipate a substantial disruption of our business although the cost of purchasing coal could increase. We have entered into all of our coal transportation contracts in the ordinary course of business. Several rail carriers are capable of serving the coalmines from where our coal originates, but several of our generating stations can be served by only one rail carrier. In the event the rail carrier to one of our generating stations fails to provide reliable service, we could experience a short-term disruption of our business. However, due to the obligation of the rail carriers to provide service under the Interstate Commerce Act, we do not anticipate any substantial long-term disruption of our business although the cost of transporting coal could increase. Natural Gas: We use natural gas as a primary fuel in our Gordon Evans, Murray Gill and Neosho Energy Centers. Natural gas for these facilities is purchased in the short-term spot market, which supplies the system with the flexible natural gas supply as necessary to meet operational needs. We meet a portion of our natural gas transportation requirements through firm natural gas transportation capacity agreements with Williams Gas Pipelines Central. The firm transportation agreement that serves Gordon Evans and Murray Gill extends through April 1, 2010, and the agreement for the Neosho facility extends through June 1, 2016. 8
Oil: We use oil as an alternate fuel when economical or when interruptions to natural gas make it necessary. Oil is obtained by spot market purchases and year-long contracts. We maintain quantities in inventory to meet emergency requirements and protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to burn. Other Fuel Matters: Our contracts to supply fuel for our coal-fired and natural gas-fired generating units, with the exception of JEC, do not provide full fuel requirements at the various stations. Supplemental fuel is procured on the spot market to provide operational flexibility and to take advantage of economic opportunities when the price is favorable. We use financial instruments to hedge a portion of our anticipated fossil fuel needs in an attempt to offset the volatility of the spot market. Due to the volatility of these markets, we are unable to determine what the value of these financial instruments will be when the agreements are actually settled. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information - -- Market Risk Disclosure" for further information. The table below provides information relating to the weighted average cost of fuel that we have used (which includes the commodity cost, transportation cost to our facilities and any other associated costs). 2001 2000 1999 ---- ---- ---- Per Million Btu: Nuclear ............................... $ 0.44 $ 0.44 $ 0.45 Coal .................................. 0.95 0.91 0.87 Gas ................................... 3.75 3.34 2.31 Oil ................................... 3.84 3.12 2.11 Per MWh Generation ...................... $11.04 $11.08 $ 9.83 Nuclear Generation Fuel Supply: The owners of Wolf Creek have on hand or under contract 100% of their uranium and uranium conversion needs for 2002 and 77% of the uranium and uranium conversion required for operation of Wolf Creek through October 2006. The balance is expected to be obtained through spot market and contract purchases. The owners have under contract 100% of Wolf Creek's uranium enrichment needs for 2002 and 90% of the uranium enrichment required to operate Wolf Creek through October 2006. The balance of Wolf Creek's enrichment needs are expected to be obtained through spot market and contract purchases. All uranium, uranium conversion and uranium enrichment arrangements have been entered into in the ordinary course of business, and Wolf Creek is not substantially dependent upon these agreements. Despite contraction and consolidation in the supply sector for these commodities and services, Wolf Creek's management believes there are other supplies available to replace, if necessary, these contracts. In the event these contracts were required to be replaced, Wolf Creek's management does not anticipate a substantial disruption of Wolf Creek's operations. Nuclear fuel is amortized to cost of sales based on the quantity of heat produced (MMBtus) for the generation of electricity. 9
Radioactive Waste Disposal: Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales. In 1996 and 1997, a U.S. Court of Appeals issued decisions that (1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for disposal in 1998 and (2) precluded the DOE from concluding that its delay in accepting spent fuel is "unavoidable" under its contracts with utilities due to lack of a repository or interim storage authority. In May 1998, the Court issued an order in response to the utilities' petitions for remedies for DOE's failure to begin accepting spent fuel for disposal. The Court affirmed its conclusion that the sole remedy for DOE's breach of its statutory obligation under the NWPA is a contract remedy and indicated that the court will not revisit the matter until the utilities have completed their pursuit of that remedy. Wolf Creek intends to pursue its claims against the DOE. A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025. 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 (Compact) and selected a site in Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact have provided most of the pre-construction financing for this project. Our net investment in the Compact through December 31, 2001 was approximately $7.4 million. On December 18, 1998, the Nebraska agencies responsible for considering the developer's license application denied the application. The license applicant has sought a hearing on the license denial, but a U.S. District Court has indefinitely delayed proceedings related to the hearing. In December 1998, most of the utilities that had provided the project's pre-construction financing (including WCNOC) filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application. Shortly thereafter, the Central Interstate Low-Level Radioactive Waste Commission (Commission) (responsible for causing a new disposal facility to be developed within the Compact region) and US Ecology (the license applicant) filed similar claims against Nebraska. In September 1999, the U.S. District Court partially denied and partially granted Nebraska's motions to dismiss the utilities' and US Ecology's cases and denied Nebraska's motions to dismiss the Compact Commission's case. Since that time, the utilities have dismissed their remaining claims against Nebraska for monetary damages, but their claims for equitable relief remain. The Commission's claims for monetary damages and equitable relief also remain, and the parties expect the case to go to trial in the second half of 2002. In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska from the Compact. In August 1999, the Nebraska governor gave official notice of the withdrawal to the other member states. Withdrawal will not be effective for five years and will not, of itself, nullify the site license proceeding. 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 for up to five years under current regulations. Wolf Creek believes that a temporary loss of low-level radioactive waste disposal capability will not affect continued operation of the power plant. 10
Outages: Wolf Creek has an 18-month refueling and maintenance schedule which permits uninterrupted operation every third calendar year. An outage began on March 23, 2002. During the outage, electric demand is expected to be met primarily by our other fossil-fueled generating units and by purchased power. An extended shut-down of Wolf Creek could have a substantial adverse effect on our business, financial condition and results of operations because of higher replacement power and other costs. Although not expected, reacting to safety issues, the Nuclear Regulatory Commission (NRC) could impose an unscheduled plant shut-down due to terrorist or other concerns. Security and Insurance We have increased security measures at our generation facility sites and various offices, in part due to nationwide terrorist concerns. These measures include, but are not limited to, increased security personnel, utilization of armed guard services, patrolling of company property, restricting access to our properties and implementing emergency training and response procedures. Wolf Creek's management has increased both voluntary and federally-mandated security measures at Wolf Creek. The NRC has required nuclear power plants to be operated at the highest level of security since September 11, 2001. The measures implemented at Wolf Creek include, but are not limited to, increased guard service, no unscheduled visits and emergency training and response procedures. The NRC has issued orders to all nuclear plants that make our current voluntary security measures mandatory. The orders also impose new security requirements at U.S. nuclear power plants. Wolf Creek's security costs will increase as a result of these orders. In addition, there are unfavorable trends in the availability and price of property and casualty insurance primarily due to catastrophic events and the world's financial markets. We anticipate material increases in insurance costs, although the amount of the increase is unknown at this time. Information with respect to insurance coverage applicable to the operations of our nuclear generating facility is set forth in Note 11 of the "Notes to Consolidated Financial Statements." Competition and Deregulation Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000. In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self-generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our average retail rates are approximately 10% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment. Increased competition for retail electricity sales may in the future reduce our earnings, which could impact our ability to pay dividends and could have a material adverse impact on our operations and our financial condition. A material non-cash charge to earnings may be required should we discontinue accounting under Statement of Financial Accounting Standard No. 71, "Accounting for the Effects of Certain Types of Regulation." 11
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 sell electric power to wholesale customers. In 1992, we agreed to open access of 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 (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). 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. After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and MISO agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations. For further discussion regarding competition and its potential impact on us, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Electric Utility." 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, valuation of property, the classification of accounts and various other matters. Additionally, we are subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of certain securities. We are also subject to the jurisdiction of the KCC and the FERC with respect to the issuance of certain securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. On November 27, 2000, Western Resources and we filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our electric rates of $41.2 million. On August 9, 2001, Western Resources and we filed a petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2 and several other issues. On September 5, 2001, the KCC issued an order denying our motion for reconsideration, which did not change our rate reduction. On November 9, 2001, we filed an appeal of the KCC decisions to the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court. Additional information with respect to Rate Matters and Regulation is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Summary of Significant Items -- KCC Rate Cases," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Electric Utility" and Note 3 of the "Notes to Consolidated Financial Statements." Environmental Matters We currently hold all Federal and State environmental approvals required for the operation of all of our generating units. We believe we are presently in substantial compliance with all air quality regulations (including 12
those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA). The JEC and LaCygne 2 units have met: (1) the Federal sulfur dioxide standards through the use of low sulfur coal; (2) the Federal particulate matter standards through the use of electrostatic precipitators; and (3) the federal NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits. The Kansas Department of Health and Environment (KDHE) regulations applicable to our other generating facilities prohibit the emission of more than 3.0 pounds of sulfur dioxide per MMBtu of heat input. We meet these standards through the use of low sulfur coal and by all coal-burning facilities being equipped with flue gas scrubbers and/or electrostatic precipitators. We must comply, and are currently in compliance, with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II sulfur dioxide and nitrogen oxide requirements. All of our generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the KDHE. Additional information with respect to Environmental Matters is discussed in Note 11 of the "Notes to Consolidated Financial Statements." SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 16 of the "Notes to Consolidated Financial Statements." EMPLOYEES All employees we utilize are provided by Western Resources. RISK FACTORS You should read the following risk factors in conjunction with discussions of factors discussed elsewhere in this and other of our filings with the Securities and Exchange Commission. These cautionary statements are intended to highlight certain factors that may affect our financial condition and results of operations and are not meant to be an exhaustive discussion of risks that apply to public companies, such as us. Like other businesses, we are susceptible to macroeconomic downturns in the United States or abroad that may affect the general economic climate and our performance or that of our customers. We Are a Public Utility Subject to Regulation Which Significantly Impacts Our Business, Results of Operations, Financial Position and Prospects: We are regulated by the KCC and FERC and other federal and state agencies. See "-- Electric Utility Operations -- Regulation and Rates." This regulation impacts most aspects of our business and operations. Throughout this Annual Report on Form 10-K, we have described the impact of regulation and the significant effect it has on our business, financial condition, results of operations, liquidity and prospects. Such regulation is impacted by matters beyond our control, such as general economic conditions, politics and competition, and other matters 13
described under "Forward-Looking Statements." We refer you to "--Significant Business Developments," and the other risk factors below, as well as "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations", for a further discussion of some of the more important matters which are currently the subject of, or related to, regulatory concerns. Municipalization Efforts by Wichita May Affect Operations and Results: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace us as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize our Wichita electric facilities, the City of Wichita would be required to purchase our facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize our retail electric utility business in Wichita. We will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. Our franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, we will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 51% of our total energy sales. Fuel and Purchased Power Costs are Included in Retail Rates at a Fixed Level and Increases are not Recovered Automatically: Fuel and purchased power costs are recovered in retail rates at a fixed test year level. Therefore, to recover fuel and purchased power costs in excess of the costs built into retail rates, we would have to make a rate filing with the KCC, which could be denied in whole or in part. During 2001, we entered into a gas hedging arrangement, designed to eliminate a portion of our risk through July 2004. Any increase in fuel and purchased power costs over the costs recovered through rates would reduce our earnings. Increases could be material. Purchased Power Commodity Prices are Volatile: The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to fluctuating market prices that may adversely impact our financial position and results of operations. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition. Hedging and Trading Activities Involve Risks: We are involved in hedging and trading activities primarily to minimize risk from commodity market fluctuations, capitalize on market knowledge and enhance system reliability. In these activities, we utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, futures, options and swaps providing for payments (or receipt of payments) from counter parties based on the differential between the contract price and a specified index price. Our 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 fossil fuels for our generators. These commodities have experienced price 14
volatility in the past and can be expected to do so in the future. This volatility may increase or decrease future earnings. Interest rate risk is the risk of loss associated with movements in market interest rates. Our exposure to interest rate risk is limited due to the fixed-rate nature of most of our long-term debt. Credit risk is the risk of loss resulting from non-performance by a counter party of its contractual obligations. As we continue to expand our commodity trading activities, our exposure to credit risk and counter party default may increase. We maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. We employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counter party is limited until credit enhancement is provided. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Market Risk Disclosure" for further discussion. Results actually achieved from these activities could vary materially from intended results and could materially affect our financial results. Our and Western Resources' Current Levels of Debt Could Adversely Affect Our Business: Western Resources and we have a large amount of indebtedness. As of December 31, 2001, we had outstanding total indebtedness of approximately $684.4 million. A large amount of indebtedness could have a negative impact on, among other things, Western Resources' ability to provide for our short-term cash needs and our ability to obtain replacement financing if such event were to occur. The indentures governing our long-term indebtedness require us to satisfy certain financial conditions in order to borrow additional funds. These covenants require, among other things, that we maintain certain leverage and interest coverage ratios. We are in compliance with these covenants. A breach of any of the covenants could result in an event of default, which would allow the lenders to declare all amounts outstanding immediately due and payable. For information regarding a financial plan that was filed by Western Resources with the KCC that details Western Resources' current plans for debt reduction, see "--Significant Business Developments -- KCC Proceedings and Orders" and "--Significant Business Developments -- The Financial Plan" above. Strategic Transactions May Not Be Completed: Western Resources and our strategic plans include the acquisition of Western Resources' electric utility businesses (including us) by PNM and the split-off of Westar Industries to Western Resources' shareholders. Prior to the completion of these transactions, Westar Industries would sell a portion of its common stock in a rights offering to Western Resources' shareholders. The completion of these transactions is subject to the satisfaction of various conditions including the receipt of shareholder and regulatory approvals in the case of the PNM transaction. Western Resources and we believe the completion of the proposed transaction with PNM is not likely. See "--Significant Business Developments -- PNM Transaction" above for more information. 15
ITEM 2. PROPERTIES ELECTRIC GENERATING FACILITIES - ------------------------------------------------------------------------------------------------------------------------------ Year Principal Unit Name Unit No. Installed Fuel Capacity (MW) Segment - ------------------------------------------------------------------------------------------------------------------------------ Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 151.0 Electric Operations 2 1967 Gas--Oil 383.0 Electric Operations Diesel Generator 1 1969 Diesel 3.0 Electric Operations - ------------------------------------------------------------------------------------------------------------------------------ Jeffrey Energy Center (20%): Steam Turbines 1 (a) 1978 Coal 149.0 Electric Operations 2 (a) 1980 Coal 146.0 Electric Operations 3 (a) 1983 Coal 148.0 Electric Operations Wind Turbines 1 (a) 1999 - 0.2 Electric Operations 2 (a) 1999 - 0.2 Electric Operations - ------------------------------------------------------------------------------------------------------------------------------ LaCygne Station (50%): Steam Turbines 1 (a) 1973 Coal 344.0 Electric Operations 2 (b) 1977 Coal 337.0 Electric Operations - ------------------------------------------------------------------------------------------------------------------------------ Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 43.0 Electric Operations 2 1954 Gas--Oil 74.0 Electric Operations 3 1956 Gas--Oil 112.0 Electric Operations 4 1959 Gas--Oil 107.0 Electric Operations - ------------------------------------------------------------------------------------------------------------------------------ Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 69.0 Electric Operations - ------------------------------------------------------------------------------------------------------------------------------ Wolf Creek Generating Station (47%): Nuclear 1 (a) 1985 Uranium 550.0 Nuclear Generation - ------------------------------------------------------------------------------------------------------------------------------ Total 2,616.4 - ------------------------------------------------------------------------------------------------------------------------------ - ---------- (a) We jointly own Jeffrey Energy Center (20%), LaCygne 1 generating unit (50%), and Wolf Creek Generating Station (47%). Western Resources jointly owns 64% of Jeffrey Energy Center. (b) In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the LaCygne 2 generating unit. We own approximately 2,400 miles of transmission lines, approximately 9,900 miles of overhead distribution lines and approximately 1,800 miles of underground distribution lines. (These properties are part of the Electric Operations segment.) Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding. 16
ITEM 3. LEGAL PROCEEDINGS Information on our legal proceedings is set forth in Notes 3, 11, 12, and 13 of the "Notes to Consolidated Financial Statements." See also "Item 1. Business -- Electric Utility Operations -- Regulation and Rates," and "Item 1. Business -- Electric Utility Operations -- Environmental Matters." ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Information required by Item 4 is omitted pursuant to General Instruction I(2)(c) to Form 10-K. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of our common stock is owned by Western Resources and is not traded on an established public trading market. ITEM 6. SELECTED FINANCIAL DATA For the Year Ended December 31, -------------------------------------------------------------- 2001 2000 1999 1998 1997 ---------- ---------- ---------- ---------- ---------- Income Statement Data: Sales ............................. $ 673,125 $ 703,990 $ 638,340 $ 648,379 $ 614,445 Net income before accounting change 37,301 86,708 84,261 103,765 52,128 As of December 31, -------------------------------------------------------------- 2001 2000 1999 1998 1997 ---------- ---------- ---------- ---------- ---------- Balance Sheet Data: Total assets ...................... $2,930,045 $2,988,573 $2,989,710 $3,057,971 $3,117,108 Long-term debt, net ............... 684,360 684,366 684,271 684,167 684,128 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In Management's Discussion and Analysis, we discuss the general financial condition, significant annual changes and our operating results. We explain: . what factors impact our business, . what our earnings and costs were in 2001, 2000 and 1999, . why these earnings and costs differ from year to year, . how our earnings and costs affect our overall financial condition, . what our capital expenditures were for 2001, . what we expect our capital expenditures to be for the years 2002 through 2004, . how we plan to pay for these future capital expenditures, . critical accounting policies, and . any other items that particularly affect our financial condition or earnings. As you read Management's Discussion and Analysis, please refer to our consolidated financial statements and the notes thereto, which show our operating results. SUMMARY OF SIGNIFICANT ITEMS PNM Transaction On November 8, 2000, Western Resources entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire Western Resources' electric utility businesses (including us) in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and Western Resources are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. At the same time Western Resources entered into the agreement with PNM, Western Resources and Westar Industries, a wholly owned subsidiary of Western Resources, entered into an Asset Allocation and Separation Agreement, which provided for a split-off of Westar Industries and related matters. On October 12, 2001, PNM filed a lawsuit against Western Resources in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for Western Resources' electric utility businesses. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, Western Resources filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of Western Resources' electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, Western Resources filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to Western Resources purporting to terminate the merger in accordance with the terms of the merger agreement. Western Resources has notified PNM that it believes the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. Western Resources intends to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, Western Resources believes the closing of the proposed merger is not likely. 18
KCC Rate Cases On November 27, 2000, Western Resources and we filed applications with the KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC issued orders that reduced our electric rates by $41.2 million. Western Resources and we appealed these orders to the Kansas Court of Appeals, but the KCC orders were upheld. We are evaluating whether to appeal the decision to the Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Summary of Significant Items -- KCC Rate Cases" for further discussion. KCC Proceedings and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of Western Resources' electric utility businesses (including us) from its non-utility businesses, including the rights offering, and other aspects of its unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving Western Resources' unregulated businesses are consistent with its obligation to provide efficient and sufficient electric service at just and reasonable rates to its electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement Western Resources entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by Western Resources to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by Western Resources' unregulated businesses and whether they should continue to be affiliated with its electric utility business, and Western Resources' present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Western Resources from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting Western Resources and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed Western Resources and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in Western Resources' capital structure applicable to its electric utility operations, which has the effect of prohibiting it from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed Western Resources to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of its non-utility businesses. In its order, the KCC also acknowledged that Western Resources and we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. Western Resources appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that Western Resources and the KCC staff make filings addressing whether the filing of applications by Western Resources and us at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that Western Resources not increase the share of debt in its capital structure applicable to its electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC staff filed a motion to intervene in the proceeding at FERC asserting the same position. Western Resources is unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing Western Resources' and our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on Western Resources' or our ability to refinance indebtedness maturing in the 19
next several years. Western Resources' or our inability to refinance existing indebtedness on a secured basis would likely increase borrowing costs and adversely affect Western Resources' and our results of operations. The Financial Plan The July 20, 2001 KCC order directed Western Resources to present a financial plan to the KCC. Western Resources presented a financial plan to the KCC on November 6, 2001, which it amended on January 29, 2002. The principal objective of the financial plan is to reduce Western Resources' total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that Western Resources will proceed with the rights offering and that, in the event that the PNM merger and related split-off do not close, Western Resources will use its best efforts to sell its share of Westar Industries common stock, or shares of its common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. Western Resources is unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take. Ice Storm In late January 2002, a severe ice storm swept through our service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs to be approximately $13 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. CRITICAL ACCOUNTING POLICIES Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, goodwill, intangible assets, income taxes, and contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. Note 2 of the "Notes to Consolidated Financial Statements" includes a summary of the significant accounting policies and methods used in the preparation of our consolidated financial statements. The following is a brief description of the more significant accounting policies and methods used by us. Regulatory Accounting We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. As of December 31, 2001, this would reduce our earnings by $239.9 million, net of applicable income taxes. 20
SFAS No. 71 affects our electric operations and nuclear generation business segments. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See "--Competition and Deregulation" and "--Stranded Costs" for additional discussion of the application of SFAS No. 71. Sales Recognition Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for energy trading activities. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets. We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense. Depreciation Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 2.80% during 2001, 2.81% during 2000 and 2.76% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $14.3 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application. Depreciable lives of property, plant and equipment are as follows: Fossil generating facilities ............ 10 to 46 years Nuclear generating facilities ........... 38 years Transmission facilities ................. 27 to 65 years Distribution facilities ................. 20 to 65 years Other ................................... 3 to 50 years Income Taxes Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. Investment tax credits previously deferred are being amortized to income over the life of the property that gave rise to the credits. Cumulative Effect of Accounting Change Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). Derivative instruments (primarily swaps, options and futures) are used to manage interest rate exposure and the commodity price risk inherent in fossil fuel purchases and electricity sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value. 21
Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $12.9 million, net of $8.5 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle. After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized currently in revenue as discussed above under "- Sales Recognition." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings. OPERATING RESULTS We supply electric energy at retail to approximately 293,000 customers in Kansas. These customers are classified below as residential, commercial and industrial as defined in our tariffs. Sales classifications and the related descriptions for our remaining electricity sales are as follows: . Wholesale: Sales consist of electric energy supplied to the electric distribution systems of 27 Kansas cities. It also includes contracts for the sale, purchase or exchange of electricity with other utilities and/or marketers. . System Marketing: Financial transactions entered into on behalf of system requirements. . Other: Includes public street and highway lighting and miscellaneous electric revenues. Many things will affect our future sales. Our regulated electric utility sales are significantly impacted by such things as the weather, regulation (including rate regulation), customer conservation efforts, wholesale demand, the overall economy of our service area, the City of Wichita's attempt to create a municipal electric utility, and competitive forces. Our sales are impacted by demand outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity. Our electric sales for the last three years ended December 31 are as follows: 2001 2000 1999 ---- ---- ---- (In Thousands) Residential .................... $222,427 $246,665 $220,645 Commercial ..................... 175,899 175,686 169,427 Industrial ..................... 155,990 161,693 163,158 Other .......................... 24,970 23,690 21,855 -------- -------- -------- Total retail ............... $579,286 $607,734 $575,085 Wholesale ...................... 77,762 78,596 63,255 System Marketing ............... 16,077 17,660 -- -------- -------- -------- Total ...................... $673,125 $703,990 $638,340 ======== ======== ======== 22
The following tables reflect changes in electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No sales volumes are included for system marketing sales because these sales are not based on electricity we generate. 2001 2000 % Change ---- ---- -------- (Thousands of MWh) Residential .......................... 2,734 2,950 (7.3) Commercial ........................... 2,632 2,544 3.5 Industrial ........................... 3,488 3,561 (2.0) Other ................................ 44 45 (2.2) ------ ------ Total retail ..................... 8,898 9,100 (2.2) Wholesale ............................ 2,479 2,407 3.0 ------ ------ Total ............................ 11,377 11,507 (1.1) ====== ====== 2000 1999 % Change ---- ---- -------- (Thousands of MWh) Residential .......................... 2,950 2,601 13.4 Commercial ........................... 2,544 2,413 5.4 Industrial ........................... 3,561 3,548 0.4 Other ................................ 45 45 -- ------ ------ Total retail ..................... 9,100 8,607 5.7 Wholesale ............................ 2,407 1,832 31.4 ------ ------ Total ............................ 11,507 10,439 10.2 ====== ====== 2001 compared to 2000: Net income before accounting change decreased $36.5 million, or 42%. External sales decreased $30.9 million, or 4%. Residential sales revenue declined approximately 10% and system marketing sales declined approximately 9%. Residential sales decreased due to weather conditions and our rate decrease, while system marketing sales decreased because of lower prices. As a result of the higher cost of sales and operating expenses discussed below and reduced revenues, EBIT decreased $85.0 million, or 50%. Excluding the mark-to-market adjustment on fuel derivatives, EBIT would have decreased $63.7 million. Cost of sales increased $36.5 million, or 21%, primarily due to a $21.3 million non-cash mark-to-market adjustment on fuel derivatives as prescribed by SFAS No. 133, a $5.0 million increase in purchased power costs and a $14.2 million increase in costs associated with the dispatching of electric power. These increases were partially offset by a decrease in fuel expenses of $4.0 million. Gross profit decreased $67.4 million, or 13%. Operating expenses increased $16.2 million, or 5%, because of higher operating and maintenance expenses associated with planned outages and increased selling, general and administrative expenses. 2000 compared to 1999: Net income before accounting change increased $2.4 million and total gross profit increased $12.6 million, or 2%. These increases are due primarily to a 13% increase in residential sales volumes and a 31% increase in wholesale sales volumes. The increase in residential sales is primarily due to increased demand caused by warm weather. Cooling-degree days increased by 27%. The increase in wholesale sales volumes was primarily due to increased wholesale market opportunities. Items included in energy cost of sales are fuel expense and purchased power expense (electricity we purchase from others for resale). Partially offsetting the higher sales was an increase of $53.0 million in cost of sales primarily due to increased fuel and purchased power expenses of approximately $25.5 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale sales volumes. 23
Business Segments We have defined two business segments, electric operations and nuclear generation, based on how management currently evaluates our business. Our business segments are based on differences in products and services, production processes and management responsibility. We manage our business segments' performance based on their earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by GAAP, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund our cash needs. Items excluded from EBIT are significant components in understanding and assessing our financial performance. We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by us to satisfy our debt service obligations, capital expenditures and other operational needs, as well as to provide funds for growth. Our computation of EBIT may not be comparable to other similarly titled measures of other companies. When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy. The following table reflects key information for our two electric utility business segments: For the years ended December 31, -------------------------------- 2001 2000 1999 ---- ---- ---- (In Thousands) Electric Operations: External sales ...................... $ 673,125 $ 703,990 $ 638,340 Depreciation and amortization ....... 64,090 64,242 61,531 Earnings before interest and taxes (EBIT) (a) ............... 104,390 194,611 193,980 Additions to property, plant and equipment ........................ 55,402 56,839 53,538 Nuclear Generation (b): Internal sales ...................... $ 117,659 $ 107,770 $ 108,445 Depreciation and amortization ....... 41,046 40,052 39,629 Earnings (losses) before interest and taxes (EBIT) (b) ........... (19,078) (24,323) (25,214) Additions to property, plant and equipment ........................ 27,349 25,877 10,036 - ---------- (a) EBIT shown above for Electric Operations for 2001 does not include the $21.4 million unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle as discussed in Note 5 of the "Notes to Consolidated Financial Statements". If the effect had been included, EBIT for the Electric Operations segment for the year ended December 31, 2001 would have been $125,808. (b) Nuclear Generation amounts represent our 47% share of Wolf Creek's operating results. Electric Operations: External sales include power produced for sale to wholesale and retail customers and the amounts associated with the system marketing transactions discussed above. 2001 compared to 2000: External sales decreased $30.9 million, or 4%. Residential sales declined approximately 10% and system marketing sales declined approximately 9%. Residential sales decreased due to weather conditions and our rate decrease, while system marketing sales decreased because of lower prices. 24
Cost of sales increased $34.0 million, or 23%, primarily due to a $21.3 million non-cash mark-to-market adjustment on fuel derivatives as prescribed by SFAS No. 133, a $6.5 million decrease in fuel expense, a $5.0 million increase in purchased power costs and a $14.2 million increase in costs associated with the dispatching of electric power. Gross profit decreased $64.9 million, or 12%. As a result of the higher cost of sales and reduced revenues, EBIT decreased $90.2 million. Excluding the mark-to-market adjustment on fuel derivatives, EBIT would have decreased $68.9 million. 2000 compared to 1999: External sales increased $65.7 million primarily due to 13% higher residential sales volumes and 31% higher wholesale sales volumes. Approximately $17.7 million in system marketing transactions also increased external sales. While sales increased $65.7 million, or 10%, EBIT increased only $0.6 million primarily due to higher cost of sales of $53.6 million. Cost of sales was higher primarily due to increased fuel and purchased power expenses of approximately $44.3 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale sales volumes. The cost of fuel in 2000 was significantly affected by increased gas costs of $9.2 million (despite an 11.2% reduction in MMBtu of gas burned). Our average natural gas price increased 45% during the year compared to 1999. Additionally, coal costs increased by $8.2 million primarily due to increasing the quantities of coal burned in our efforts to minimize gas costs and cost of oil increased $3.3 million primarily due to increased price and increasing the quantities of oil burned. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Market Risk Disclosure" for further discussion. Operation and maintenance expenses increased $7.0 million primarily due to our increased sales. Other expense increased $3.5 million primarily due to transaction costs associated with the sale of our accounts receivable in a financing transaction and because of a gain recorded in 1999 on the disposition of property. Nuclear Generation: Nuclear Generation has only internal sales because all of its power is provided to its co-owners: Kansas City Power and Light Company (KCPL), Kansas Electric Power Cooperative, Inc. and us. We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Internal sales are priced at an internal transfer price that Nuclear Generation charges to Electric Operations. Wolf Creek operated the entire year of 2001 without any refueling outages. Wolf Creek shut down for 38 days beginning on September 29, 2000 for its eleventh scheduled refueling and maintenance outage. Internal sales and EBIT increased during 2001 since the unit operated more during 2001 than during 2000. During 1999, there was a 36-day refueling and maintenance outage at Wolf Creek. Since both 2000 and 1999 had refueling outages, the change in internal sales and EBIT between 2000 and 1999 was immaterial. Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. An outage began on March 23, 2002. During an outage, Wolf Creek produces no power for its co-owners; therefore internal sales, EBIT and nuclear fuel expense decrease. Income Taxes 2001 compared to 2000: We recorded an income tax benefit in 2001 of $1.6 million and income tax expense in 2000 of $34.0 million. Our effective income tax rates were a benefit of 5% for December 31, 2001 and an expense of 28% for December 31, 2000. This change is primarily due to lower earnings before income taxes in 2001. Earnings before income taxes decreased due to reduced sales volumes, a reduction in retail sales and system marketing transactions, 25
and rate reductions ordered by the KCC in July 2001. Our effective tax rates are also affected by the amortization of prior years' investment tax credits and the tax benefit from corporate-owned life insurance. 2000 compared to 1999: The Federal statutory rate produced effective income tax rates of 28% for 2000 and 29% for 1999. The effective income tax rates are lower than the Federal statutory rate of 35% due to differences, such as amortization of investment tax credits and benefits from corporate-owned life insurance. LIQUIDITY AND CAPITAL RESOURCES Overview Most of our cash requirements consist of capital expenditures and maintenance costs designed to improve and maintain facilities that provide electric service and meet future customer service requirements. Our ability to provide the cash or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions. Funds are available to us from the sale of securities we register for sale with the Securities and Exchange Commission. As of December 31, 2001, $50.0 million of KGE first mortgage bonds were registered. Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our 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 first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2001, approximately $279 million principal amount of additional first mortgage bonds could be issued under the most restrictive tests in the mortgage. Our internally generated cash is generally sufficient to fund operations and debt service payments. We do not maintain independent short-term credit facilities and rely on Western Resources for short-term cash needs. If Western Resources is unable to borrow under its credit facilities, we could have a short term liquidity issue which could require us to obtain a credit facility for our short-term cash needs and which could result in higher borrowing costs. On June 28, 2000, Western Resources entered into a $600 million, multi-year term loan that replaced two revolving credit facilities that matured on June 30, 2000. The term loan is secured by our and Western Resources' first mortgage bonds and has a final maturity date of March 17, 2003. Western Resources also has an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and Western Resources' first mortgage bonds and matures on March 17, 2003. The table below shows the projected future cash payments for our contractual obligations existing at December 31, 2001: At December 31, 2001: Payments Due by Period ------------------------------------------------------------ Total 2002 2003 - 2004 2005 - 2006 Thereafter ---------- ------- ----------- ----------- ---------- (In Thousands) Contractual Obligations Long-term debt ................... $ 684,360 $ -- $135,000 $165,000 $ 384,360 Operating leases ................. 672,731 41,984 86,888 91,584 452,275 Fossil fuel ...................... 485,540 56,956 69,196 48,520 310,868 Nuclear fuel ..................... 84,038 -- 27,449 10,389 46,200 ---------- ------- -------- -------- ---------- Total contractual obligations $1,926,669 $98,940 $318,533 $315,493 $1,193,703 ========== ======= ======== ======== ========== 26
Credit Ratings Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and Moody's Investors Service (Moody's) are independent credit-rating agencies that rate Western Resources' and our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal on these securities. On June 1, 2001, Moody's placed Western Resources' and our ratings under review with direction uncertain. On October 19, 2001, S&P removed us from its CreditWatch listing and changed Western Resources' and our ratings outlook to "negative." On November 7, 2001, S&P reaffirmed its negative outlook for Western Resources and us. As of March 14, 2002, ratings with these agencies are as follows: Western Western Resources Resources Mortgage Unsecured KGE Mortgage Bond Rating Debt Bond Rating ----------- --------- ------------ S&P ............... BBB- BB- BB+ Fitch ............. BB+ BB BB+ Moody's ........... Ba1 Ba2 Ba1 In general, declines in Western Resources' and our credit ratings make debt financing more costly and more difficult to obtain on terms which are economically favorable to us. Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non-utility businesses. We do not have any credit rating conditions in any of the agreements under which our debt has been issued. Sale of Accounts Receivable On July 28, 2000, Western Resources and we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001 and is annually renewable upon agreement by both parties. Under the terms of the agreement, Western Resources and we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned by Western Resources and consolidated by us. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. Western Resources services the receivables transferred to the SPE and receives a servicing fee, which approximates market compensation for these services. Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest. We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income. 27
At December 31, 2001 and 2000, the outstanding balance of SPE receivables was $43.3 million and $85.5 million, which is net of an undivided interest of $100.0 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets. Cash Flows from (used in) Operating Activities Our primary source of operating cash flows are the operations of our electric utility. Cash flows from operating activities decreased $60.2 million to $145.6 million in 2001, from $205.8 million in 2000. This decrease is mostly attributable to changes in our working capital. Operating cash flows produced in 2001 also decreased because we purchased additional coal and oil to restock our inventory from the levels that existed in December 2000. Cash flows from operating activities decreased $4.6 million to $205.8 million in 2000, from $210.4 million in 1999. This decrease is mostly attributable to changes in working capital. Cash Flows from (used in) Financing Activities Net cash used in financing activities totaled $64.4 million for the year ended December 31, 2001 as compared to $116.1 for the same period of 2000 due primarily to changes in net advances to Western Resources. Future Cash Requirements We believe that internally generated funds and borrowings from Western Resources will be sufficient to meet our operating and capital expenditure requirements and debt service payments through at least the year 2004. Uncertainties affecting our ability to meet these requirements include the factors affecting sales described above, the impact of inflation on operating expenses, regulatory action, the impact of the rate reduction, Western Resources' ability to consummate the financial plan furnished to the KCC and to refinance outstanding debt discussed under "--Summary of Significant Items -- KCC Proceedings and Orders" above, compliance with future environmental regulations and municipalization efforts by the City of Wichita. We forecast that we will need additional capacity of approximately 150 megawatts (MW) by 2006 to serve our customer's expected electricity needs. We will determine how to meet this need at a future date. In 2003, $135 million of our first mortgage bonds will mature and $65 million of our first mortgage bonds will mature in 2005. Our business requires significant capital investments. We currently expect that through the year 2004, we will need cash mostly for ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. Capital expenditures for 2001 and anticipated capital expenditures for 2002 through 2004 are as follows: Electric Nuclear Operations Generation Total ---------- ---------- ----- (In Thousands) 2001.......... $55,402 $27,349 $82,751 2002.......... 53,900 10,000 63,900 2003.......... 66,000 30,100 96,100 2004.......... 65,300 30,100 95,400 These estimates are prepared for planning purposes and will be revised from time to time. See Note 2 of the "Notes to Consolidated Financial Statements." Actual expenditures will differ from our estimates. 28
Capital Structure Our capital structure at December 31, 2001 and 2000 was as follows: 2001 2000 ---- ---- Shareholder's equity ...... 61% 62% Long-term debt, net ....... 39 38 --- --- Total ................. 100% 100% === === OTHER INFORMATION Electric Utility City of Wichita Municipalization Effort: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace us as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize our Wichita electric facilities, the City of Wichita would be required to purchase our facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize our retail electric utility business in Wichita. We will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. Our franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, we will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 51% of our total energy sales. FERC Proceedings: In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between Western Resources' KPL division and KGE. The City of Wichita asked that FERC equalize the generation costs between KPL and us, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. We anticipate no further activity regarding this complaint because the City of Wichita's time to appeal FERC's order has expired. Competition and Deregulation: Electric utilities have historically operated in a rate regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000. 29
In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self-generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our average retail rates are approximately 10% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment. Increased competition for retail electricity sales may in the future reduce our earnings, which could have a material adverse impact on our operations and our financial condition. A material non-cash charge to earnings may be required should we discontinue accounting under SFAS No. 71. See "-Stranded Costs" below for additional information regarding SFAS No. 71. The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of 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 (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). 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. After the FERC rejected several attempts by the Southwest Power Pool (SPP) to seek RTO status, the SPP and the Midwest Independent System Operator, Inc. (MISO) agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations. Stranded Costs: The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets that exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our fossil generation, nuclear generation and power delivery operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material extraordinary non-cash charge to operations. Reasons for discontinuing SFAS No. 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred, a significant change by regulators from a cost-based rate regulation to another form of rate regulation and the impact should the City of Wichita municipalization efforts be successful. We periodically review SFAS No. 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based upon competitive or other events, such as the successful municipalization efforts by areas we serve, the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek, may be significantly impacted. Regulatory changes, including competition or successful municipalization efforts by the City of Wichita, could adversely impact our ability to recover our investment in these assets. As of December 31, 2001, we have 30
recorded regulatory assets that are currently subject to recovery in future rates of approximately $244.1 million. Of this amount, $174.4 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs and include coal contract settlement costs, deferred plant costs and debt issuance costs. In a competitive environment or because of such successful municipalization efforts, we may not be able to fully recover our entire investment in Wolf Creek. We presently own 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net income will be lower than our historical net income has been unless we compensate for the loss of such income with other measures. Nuclear Decommissioning: Decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant. 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 decommissioning. These plans are designed so that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant. We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs for labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000. Decommissioning costs are currently being charged to operating expense in accordance with prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%. Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. Asset Retirement Obligations: In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset. The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the 31
accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time. Related Party Transactions Our cash management function, including cash receipts and disbursements, is performed by Western Resources. An intercompany account is used to record net receipts and disbursements between KGE and Western Resources and KGE and WR Receivables Corporation. The net amount receivable from affiliates approximated $17.3 million at December 31, 2001 and $53.1 million at December 31, 2000 as reflected in our consolidated balance sheets. Certain operating expenses have been allocated to us from Western Resources. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other appropriate factors. Management believes such allocation procedures are reasonable. During 2001, we declared dividends to Western Resources of $100 million. During the fourth quarter of 2001, we entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One, a subsidiary of Westar Industries, which is a wholly owned subsidiary of Western Resources for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings. Market Risk Disclosure Market Price Risks: We are exposed to market risk, including market changes, changes in commodity prices and interest rates. Commodity Price Exposure: We are exposed to commodity price changes and use derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of market prices. From 2000 to 2001, we experienced an 11% decrease in the average price per MW of electricity purchased for utility operations. However, purchased power markets are volatile and if we were to have a 10% increase from 2001 to 2002, given the amount of power purchased for utility operations during 2001, we would have an exposure of approximately $1.3 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices. We use a mix of various fuel types, including coal and natural gas, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk, associated with this commodity type. However, from January 1, 2001 to December 31, 2001, we experienced a 7.3% increase in our average cost for natural gas purchased for utility operations, or an increase of $0.24 per MMBtu. The higher natural gas prices increased our total cost of gas purchased during 2001 by approximately $1.8 million although we decreased the quantity burned by 4.9 million MMBtu. If we were to have a similar increase from 2001 to 2002, we would have an exposure of approximately $2.0 million of operating income. Based on MMBtus of natural gas and fuel oil burned during 2001, we had exposure of approximately $4.5 million of operating income for a 10% change in average price paid per MMBtu. Due to the volatility of natural gas prices, past prices cannot be used to predict future prices. Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically year to year based on the individual fuel's availability, price, deliverability, unit outages and nuclear refueling. Our customer's electricity usage could also vary dramatically year to year based on the weather or other factors. 32
Interest Rate Exposure: We had approximately $46.4 million of variable rate debt as of December 31, 2001. A 100 basis point change in each debt series' benchmark rate at December 31, 2001, used to set the rate for such series would impact net income on an annual basis by approximately $0.3 million after tax. Hedging Activity: In an effort to mitigate fuel commodity price market risk, Western Resources and we jointly use hedging arrangements to minimize our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent upon the market prices and the extent and effectiveness of any hedging arrangements we enter. During the third quarter of 2001, Western Resources entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. Western Resources is using futures and swap contracts of which our allocated portion of the total notional volume is 26,910,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. We are allocated our proportionate share of the benefits and costs of Western Resources' commodity price risk management program based on fuel forecasts for Western Resources and us. These allocated benefits and costs are recognized in our financial statements. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133. The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for 2001: Natural gas Hedge (a) ----------- (Dollars in Thousands) Fair value of derivative instruments: Current................................................ $ (6,892) Long-term.............................................. (6,103) --------- Total............................................... $ (12,995) ========= Amounts in accumulated other comprehensive income.......... $ (20,064) Hedge ineffectiveness...................................... 1,760 Estimated income tax benefit............................... 7,281 --------- Net comprehensive loss.............................. $ (11,023) ========= Anticipated reclassifications to earnings during 2002 (b).. $ 6,892 Duration of hedge designation as of December 31, 2001...... 31 months - ---------- (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices have dropped since we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place. (b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions. Fair Value of Energy Trading Contracts The tables below show the difference between the market value and the notional values of energy trading contracts outstanding at December 31, 2001, their sources and maturity periods: 33
Fair Value of Contracts (In Thousands) Net fair value of contracts outstanding at the beginning of the period............ $ 21,418 Contracts realized or otherwise settled during the period......................... (14,354) Fair value of new contracts entered into during the period........................ (18,277) ---------- Fair value of contracts outstanding at the end of the period...................... $ (11,213) ========== Fair Value of Contracts at End of Period ------------------------------------------------------------------ Maturity Maturity in Total Fair Less Than Maturity Maturity Excess of Source of Fair Value Value 1 Year 1-3 Years 4-5 Years 5 Years ----------- --------- ---------- --------- ------------ (In Thousands) Prices actively quoted (futures)........... $ (368) $ 33 $ (401) $ -- $ -- Prices provided by other external sources (swaps and forwards).................... (10,968) (5,224) (5,744) -- -- Prices based on models and other valuation models (options and other).............. 123 123 -- -- -- ---------- -------- ---------- --------- -------- $ (11,213) $ (5,068) $ (6,145) $ -- $ -- ========== ======== ========== ========= ======== ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information relating to market risk disclosure is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Market Risk Disclosure" included herein. 34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants........................................................... 36 Financial Statements: Consolidated Balance Sheets, December 31, 2001 and 2000....................................... 37 Consolidated Statements of Income and Comprehensive Income (Loss) for the years ended December 31, 2001, 2000 and 1999.......................................................... 38 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999...................................................................................... 39 Consolidated Statements of Shareholder's Equity for the years ended December 31, 2001, 2000 and 1999............................................................................. 40 Notes to Consolidated Financial Statements.................................................... 41 SCHEDULE OMITTED The following schedules are omitted because of the absence of the financial conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, and V 35
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Kansas Gas and Electric Company: We have audited the accompanying consolidated balance sheets of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, cash flows, and shareholder's equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits 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, the financial statements referred to above present fairly, in all material respects, the financial position of Kansas Gas and Electric Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. ARTHUR ANDERSEN LLP Kansas City, Missouri, March 27, 2002 36
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) December 31, ------------------------- 2001 2000 ----------- ---------- ASSETS CURRENT ASSETS: Cash and cash equivalents ......................................... $ 5,564 $ 7,101 Accounts receivable, net .......................................... 45,209 87,921 Receivable from affiliates ........................................ 17,349 53,107 Inventories and supplies, net ..................................... 65,531 46,388 Energy trading contracts .......................................... 4,887 -- Deferred tax assets ............................................... 1,002 -- Prepaid expenses and other ........................................ 23,312 20,591 ----------- ---------- Total Current Assets ......................................... 162,854 215,108 ----------- ---------- PROPERTY, PLANT AND EQUIPMENT, NET .................................... 2,426,875 2,450,061 ----------- ---------- OTHER ASSETS: Regulatory assets ................................................. 244,108 225,479 Other ............................................................. 96,208 97,925 ----------- ---------- Total Other Assets ........................................... 340,316 323,404 ----------- ---------- TOTAL ASSETS .......................................................... $ 2,930,045 $2,988,573 =========== ========== LIABILITIES AND SHAREHOLDER'S EQUITY CURRENT LIABILITIES: Accounts payable .................................................. $ 52,657 $ 51,149 Accrued liabilities ............................................... 36,580 28,245 Energy trading contracts .......................................... 9,970 -- Deferred income taxes ............................................. -- 11,980 Other ............................................................. 35,151 32,809 ----------- ---------- Total Current Liabilities .................................... 134,358 124,183 ----------- ---------- LONG-TERM LIABILITIES: Long-term debt, net ............................................... 684,360 684,366 Deferred income taxes and investment tax credits .................. 726,676 724,456 Deferred gain from sale-leaseback ................................. 174,466 186,294 Energy trading contracts .......................................... 6,130 -- Other ............................................................. 155,666 160,061 ----------- ---------- Total Long-Term Liabilities .................................. 1,747,298 1,755,177 ----------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 11) SHAREHOLDER'S EQUITY: Common stock, without par value; authorized and issued 1,000 shares 1,065,634 1,065,634 Accumulated other comprehensive loss, net ......................... (11,023) -- Retained earnings ................................................. (6,222) 43,579 ----------- ---------- Total Shareholder's Equity ................................... 1,048,389 1,109,213 ----------- ---------- TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY ............................ $ 2,930,045 $2,988,573 =========== ========== The accompanying notes are an integral part of these consolidated financial statements. 37
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) (Dollars in Thousands) Year Ended December 31, 2001 2000 1999 --------- -------- -------- SALES .............................................................. $ 673,125 $703,990 $638,340 COST OF SALES ...................................................... 207,176 170,672 117,647 --------- -------- -------- GROSS PROFIT ....................................................... 465,949 533,318 520,693 --------- -------- -------- OPERATING EXPENSES: Operating and maintenance expense .............................. 194,101 189,456 181,784 Depreciation and amortization .................................. 105,136 104,294 101,160 Selling, general and administrative expense .................... 73,441 62,710 65,900 --------- -------- -------- Total Operating Expenses ................................. 372,678 356,460 348,844 --------- -------- -------- INCOME FROM OPERATIONS ............................................. 93,271 176,858 171,849 OTHER EXPENSE ...................................................... 7,959 6,570 3,083 --------- -------- -------- EARNINGS BEFORE INTEREST AND TAXES ................................. 85,312 170,288 168,766 --------- -------- -------- INTEREST EXPENSE: Interest expense on long-term debt ............................. 45,644 46,241 45,920 Interest expense on short-term debt and other .................. 3,967 3,364 3,598 --------- -------- -------- Total Interest Expense ................................... 49,611 49,605 49,518 --------- -------- -------- EARNINGS BEFORE INCOME TAXES ....................................... 35,701 120,683 119,248 Income tax (benefit) expense ....................................... (1,600) 33,975 34,987 --------- -------- -------- NET INCOME BEFORE ACCOUNTING CHANGE ................................ 37,301 86,708 84,261 Cumulative effect of accounting change, net of tax of $8,520 ....... 12,898 -- -- --------- -------- -------- NET INCOME ......................................................... $ 50,199 $ 86,708 $ 84,261 ========= ======== ======== OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Unrealized holding losses on cash flow hedges arising during the period ..................................................... $ (20,064) $ -- $ -- Reclassification adjustment for activity included in net income 1,760 -- -- Income tax benefit ............................................. 7,281 -- -- --------- -------- -------- Total other comprehensive loss, net of tax ............... (11,023) -- -- --------- -------- -------- COMPREHENSIVE INCOME ............................................... $ 39,176 $ 86,708 $ 84,261 ========= ======== ======== The accompanying notes are an integral part of these consolidated financial statements. 38
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) Year Ended December 31, 2001 2000 1999 --------- --------- --------- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net income ....................................................... $ 50,199 $ 86,708 $ 84,261 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Cumulative effect of accounting change ........................... (12,898) -- -- Depreciation and amortization .................................... 105,136 104,294 101,160 Amortization of nuclear fuel ..................................... 16,965 14,971 15,464 Amortization of deferred gain from sale-leaseback ................ (11,828) (11,828) (11,828) Net deferred taxes ............................................... (12,001) (38,525) (10,155) Net changes in energy trading assets and liabilities ............. 14,327 -- -- Changes in working capital items: Accounts receivable, net ...................................... 28,026 21,187 (1,238) Inventories and supplies, net ................................. (19,143) (209) (3,059) Prepaid expenses and other .................................... (2,721) 5,534 (3,410) Accounts payable .............................................. 1,508 (3,433) (1,515) Accrued liabilities ........................................... 8,335 193 (6,147) Changes in other assets and liabilities .......................... (20,319) 26,938 46,858 --------- --------- --------- Cash flows from operating activities ................... 145,586 205,830 210,391 --------- --------- --------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Additions to property, plant and equipment, net .................. (82,751) (82,716) (63,574) --------- --------- --------- Cash flows used in investing activities ................ (82,751) (82,716) (63,574) --------- --------- --------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Advances to parent company, net .................................. 35,758 (16,020) (46,801) Retirements of long-term debt .................................... (130) (30) (20) Dividends to parent company ...................................... (100,000) (100,000) (100,000) --------- --------- --------- Cash flows used in financing activities ................ (64,372) (116,050) (146,821) --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ................. (1,537) 7,064 (4) CASH AND CASH EQUIVALENTS: Beginning of period .............................................. 7,101 37 41 --------- --------- --------- End of period .................................................... $ 5,564 $ 7,101 $ 37 ========= ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: CASH PAID FOR: Interest on financing activities, net of amount capitalized ...... $ 86,906 $ 85,308 $ 77,668 Income taxes ..................................................... -- 22,200 -- The accompanying notes are an integral part of these consolidated financial statements. 39
KANSAS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (Dollars in Thousands) Year Ended December 31, ----------------------------------------- 2001 2000 1999 ----------- ----------- ----------- Common Stock ...................... $ 1,065,634 $ 1,065,634 $ 1,065,634 ----------- ----------- ----------- Retained Earnings: Beginning balance .............. 43,579 56,871 72,610 Comprehensive income ........... 39,176 86,708 84,261 Dividends to parent company .... (100,000) (100,000) (100,000) ----------- ----------- ----------- Ending balance ................. (17,245) 43,579 56,871 ----------- ----------- ----------- Total Shareholder's Equity ........ $ 1,048,389 $ 1,109,213 $ 1,122,505 =========== =========== =========== The accompanying notes are an integral part of these consolidated financial statements. 40
KANSAS GAS AND ELECTRIC COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. DESCRIPTION OF OUR BUSINESS Kansas Gas and Electric Company (KGE, the company, we, us or our) is a rate-regulated electric utility incorporated in 1990 in the State of Kansas. We are a wholly owned subsidiary of Western Resources, Inc. and we provide rate-regulated electric service using the name Westar Energy. We are engaged principally in the generation, purchase, transmission, distribution and sale of electricity in southeastern Kansas, including the Wichita metropolitan area. Our corporate headquarters are located in Wichita, Kansas. We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). We record our proportionate share of all transactions of WCNOC as we do other jointly owned facilities. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (GAAP). Undivided interests in jointly owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation. Use of Management's Estimates The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulatory Accounting We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Cash and Cash Equivalents We consider highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. Inventories and Supplies Inventories and supplies are stated at average cost. Property, Plant and Equipment Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction projects. The AFUDC rate was 8.57% in 2001, 7.45% in 2000 and 6.00% in 1999. The cost of additions to utility plant and 41
replacement units of property are capitalized. Interest capitalized into construction in progress was $1.4 million in 2001, $1.0 million in 2000 and $1.0 million in 1999. Maintenance costs and replacement of minor items of property are charged to expense as incurred. Incremental costs incurred during scheduled Wolf Creek refueling and maintenance outages are deferred and amortized monthly over the unit's operating cycle, normally about 18 months. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation. In accordance with regulatory decisions made by the Kansas Corporation Commission (KCC), the acquisition premium of approximately $801 million resulting from Western Resources' acquisition of KGE in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization totaled $128.3 million as of December 31, 2001 and $108.2 million as of December 31, 2000. Depreciation Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 2.80% during 2001, 2.81% during 2000 and 2.76% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $14.3 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application. Depreciable lives of property, plant and equipment are as follows: Fossil generating facilities ............... 10 to 46 years Nuclear generating facilities .............. 38 years Transmission facilities .................... 27 to 65 years Distribution facilities .................... 20 to 65 years Other ...................................... 3 to 50 years Nuclear Fuel Our share of the cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to cost of sales based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $35.6 million at December 31, 2001 and $18.6 million at December 31, 2000. Spent fuel charged to cost of sales was $22.1 million in 2001, $19.6 million in 2000 and $20.1 million in 1999. 42
Regulatory Assets and Liabilities Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. Our earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets and liabilities reflected in our consolidated financial statements are as follows: As of December 31, ---------------------- 2001 2000 -------- -------- (In Thousands) Recoverable income taxes ........... $174,354 $151,841 Debt issuance costs ................ 31,271 34,215 Deferred plant costs ............... 29,499 29,921 Other regulatory assets ............ 8,984 9,502 -------- -------- Total regulatory assets ........ $244,108 $225,479 ======== ======== Total regulatory liabilities ... $ 4,247 $ 618 ======== ======== . Recoverable income taxes: Recoverable income taxes represent amounts due from customers for accelerated tax benefits which have been previously flowed through to customers and are expected to be recovered in the future as the accelerated tax benefits reverse. . Debt issuance costs: Debt reacquisition expenses are amortized over the remaining term of the reacquired debt or, if refinanced, the term of the new debt. Debt issuance costs are amortized over the term of the associated debt. . Deferred plant costs: Costs related to the Wolf Creek nuclear generating facility. We expect to recover all of the above regulatory assets in rates charged to customers. A return is allowed on deferred plant costs and coal contract settlement costs (included in "Other regulatory assets" in the table above). Cash Surrender Value of Life Insurance The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other long-term assets on our consolidated balance sheets at December 31: 2001 2000 -------- -------- (In Millions) Cash surrender value of policies (a) ....... $ 656.3 $ 595.5 Borrowings against policies ................ (643.1) (584.8) -------- -------- COLI, net ............................. $ 13.2 $ 10.7 ======== ======== ---------- (a) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 2001 and 2000. Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as other income approximated $0.3 million in 2001, $0.2 million in 2000 and $0.1million in 1999. 43
Sales Recognition Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for energy trading activities. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets. We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense. Income Taxes Our consolidated financial statements use the liability method to reflect income taxes. Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. We amortize deferred investment tax credits over the lives of the related properties. Cumulative Effect of Accounting Change Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). Western Resources uses derivative instruments (primarily swaps, options and futures) to manage the commodity price risk inherent in fossil fuel purchases and electricity sales. We are allocated our proportionate share of the benefits and costs of Western Resources' commodity price risk management program based on fuel forecasts for Western Resources and us. These allocated benefits and costs are recognized in our financial statements. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our balance sheet as either an asset or liability measured at fair value. Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Prior to January 1, 2001, gains and losses on derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $12.9 million, net of $8.5 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle. After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in sales as discussed above under "- Sales Recognition." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings. 44
Reclassifications Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 3. RATE MATTERS AND REGULATION KCC Rate Proceedings On November 27, 2000, Western Resources and we filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our electric rates of $41.2 million. On August 9, 2001, Western Resources and we filed a petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2 and several other issues. On September 5, 2001, the KCC issued an order denying our motion for reconsideration, which did not change our rate reduction. On November 9, 2001, we filed an appeal of the KCC decisions to the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court. KCC Investigation and Order See Note 12 for a discussion of the order issued by the KCC on July 20, 2001 in the KCC's docket investigating the proposed separation of Western Resources' electric utility businesses (including us) from its non-utility businesses and other aspects of Western Resources' unregulated businesses. FERC Proceedings In September 1999, the City of Wichita filed a complaint with the Federal Energy Regulatory Commission (FERC) against us alleging improper affiliate transactions between Western Resources' KPL division and us. The City of Wichita asked that FERC equalize the generation costs between KPL and us, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. The City of Wichita's time to appeal FERC's order has expired. 4. ACCOUNTS RECEIVABLE Our accounts receivable on our consolidated balance sheets are comprised as follows: December 31, -------------------------- 2001 2000 --------- --------- (In Thousands) Gross accounts receivable .................... $ 102,478 $ 144,683 Unbilled energy receivables .................. 42,731 58,238 Accounts receivable sale program ............. (100,000) (115,000) --------- --------- Accounts receivable, net ..................... $ 45,209 $ 87,921 ========= ========= On July 28, 2000, Western Resources and we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts 45
receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001 and is annually renewable upon agreement by all parties. Under the terms of the agreement, Western Resources and we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned by Western Resources and consolidated by us. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. Western Resources services the receivables transferred to the SPE and receives a servicing fee, which approximates market compensation for these services. Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest. We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income. At December 31, 2001 and 2000, the outstanding balance of SPE receivables was $43.3 million and $85.5 million, which is net of an undivided interest of $100.0 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets. 5. FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value as set forth in SFAS No. 107 "Disclosures about Fair Value of Financial Instruments." The carrying values and estimated fair values of our financial instruments are as follows: Carrying Value Fair Value --------------------- --------------------- As of December 31, --------------------------------------------- 2001 2000 2001 2000 --------- --------- --------- --------- (In Thousands) Fixed-rate debt (a) .................... $ 640,993 $ 641,123 $ 639,660 $ 635,088 - ---------- (a) Fair value is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost, which approximates fair value and are not included in the table above. The fair value estimates presented herein are based on information available at December 31, 2001 and 2000. These fair value estimates have not been comprehensively revalued for the purpose of these consolidated 46
financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein. Derivative Instruments and Hedge Accounting Western Resources and we jointly use derivative financial instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, coal and electricity. Certain derivative instruments are used for trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power and fossil fuel markets. Derivative instruments used to mange commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Energy Trading Activities: Western Resources and we jointly trade energy commodity contracts daily. Within the trading portfolio, Western Resources and we take certain positions to hedge physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We record most energy contracts, both physical and financial, at fair value. Changes in value are reflected in our consolidated statement of income. We use all forms of financial instruments, including futures, forwards, swaps and options. Each type of financial instrument involves different risks. We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in cash market prices and take advantage of selected arbitrage opportunities. We refer to these transactions as energy trading activities. Although we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio's value. To the extent we have an open position, we are exposed to fluctuating market prices that may adversely impact our financial position or results of operations. The prices we use to value price risk management activities reflect our best estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. We consider a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counter parties and the time value of money. We continuously monitor the portfolio and value it daily based on present market conditions. Future changes in our creditworthiness and the creditworthiness of our counter parties may change the value of our portfolio. We adjust the value of contracts and set dollar limits with counter parties based on our assessment of their credit quality. Non-Trading Activities - Derivative Instruments and Hedging Activities: Western Resources and we jointly use derivative financial instruments to reduce our exposure to adverse fluctuations in commodity prices, interest rates, and other market risks. When we enter into a financial instrument, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged, fluctuations in the value of the derivative instruments are generally offset by changes in the value or cash flows of the underlying exposures being hedged. We record derivatives used for hedging commodity price risk in our consolidated balance sheets at fair value as energy trading contracts. The effective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is reported as a component of accumulated other comprehensive income (loss). This amount is 47
reclassified into earnings in the period during which the hedged transaction affects earnings. Effectiveness is the degree to which gains and losses on the hedging instruments offset the gains and losses on the hedged item. The ineffective portion of the hedging relationship is recognized currently in earnings. The fair values of derivatives used to hedge or modify our risks fluctuate over time. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions and the overall reduction in our risk relating to adverse fluctuations in interest rates, commodity prices and other market factors. In addition, the net income effect resulting from our derivative instruments is recorded in the same line item within our consolidated statements of income as the underlying exposure being hedged. We also formally assess, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposures. Any ineffective portion of a financial instrument's change in fair value is immediately recognized in net income. During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are using futures and swap contracts with a total notional volume of 26,910,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133. The following table summarizes the effects our natural gas hedge had on our financial position and results of operations for the year ended December 31, 2001: Natural gas Hedge (a) ----------- (Dollars in Thousands) Fair value of derivative instruments: Current............................................... $ (6,892) Long-term............................................. (6,103) --------- Total.............................................. $ (12,995) ========= Amounts in accumulated other comprehensive income......... $ (20,064) Hedge ineffectiveness..................................... 1,760 Estimated income tax benefit.............................. 7,281 --------- Net comprehensive loss............................. $ (11,023) ========= Anticipated reclassifications to earnings during 2002 (b). $ 6,892 Duration of hedge designation as of December 31, 2001..... 31 months - ---------- (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices dropped after we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place. (b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions. 48
6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at December 31: 2001 2000 ---------- ---------- (In Thousands) Electric plant in service .................... $3,738,912 $3,674,643 Less - Accumulated depreciation .............. 1,373,161 1,288,676 ---------- ---------- 2,365,751 2,385,967 Construction work in progress ................ 27,171 33,233 Nuclear fuel, net ............................ 33,883 30,791 ---------- ---------- Net utility plant .......................... 2,426,805 2,449,991 Non-utility plant in service, net ............ 70 70 ---------- ---------- Net property, plant and equipment .......... $2,426,875 $2,450,061 ========== ========== Our depreciation expense on property, plant and equipment was $85.0 million in 2001, $84.2 million in 2000 and $81.1 million in 1999. 7. JOINT OWNERSHIP OF UTILITY PLANTS Company's Ownership at December 31, 2001 ----------------------------------------------------------------------- In-Service Accumulated Net Ownership Dates Investment Depreciation MW Percent -------------- ---------- ------------ ----- --------- (Dollars in Thousands) LaCygne 1.............. (a) June 1973 $ 188,277 $ 120,300 344.0 50 Jeffrey 1.............. (b) July 1978 72,874 34,517 149.0 20 Jeffrey 2.............. (b) May 1980 73,634 33,388 146.0 20 Jeffrey 3.............. (b) May 1983 101,585 46,387 148.0 20 Jeffrey wind 1......... (b) May 1999 208 21 0.2 20 Jeffrey wind 2......... (b) May 1999 207 21 0.2 20 Wolf Creek............. (c) Sept. 1985 1,387,391 528,268 550.0 47 - ---------- (a) Jointly owned with Kansas City Power and Light Company (KCPL) (b) Jointly owned with Aquila, Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc. Amounts and capacity presented above represent our share. Our share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to us in 1987, are included in operating expenses on our consolidated statements of income. Our share of other transactions associated with the plants is included in the appropriate classification in our consolidated financial statements. 8. SHORT-TERM BORROWINGS We had no short-term borrowings outstanding at December 31, 2001 and 2000. Our short-term liquidity needs are met from cash advances by Western Resources. Western Resources obtains funds from borrowings under its credit facilities. Western Resources has an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and Western Resources' first mortgage bonds and expires on March 17, 2003. 49
9. LONG-TERM DEBT The amount of our first mortgage bonds authorized by our Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion. Amounts of additional bonds that may be issued are subject to property, earnings, and certain restrictive provisions of the Mortgage. Electric plant is subject to the lien of the Mortgage except for transportation equipment. Long-term debt outstanding is as follows: December 31, -------------------- 2001 2000 -------- -------- (In Thousands) KGE First mortgage bond series: 7.60% due 2003 ................................... $135,000 $135,000 6 1/2% due 2005 .................................. 65,000 65,000 6.20% due 2006 ................................... 100,000 100,000 -------- -------- 300,000 300,000 -------- -------- Pollution control bond series: 5.10% due 2023 ................................... 13,493 13,623 Variable due 2027, 1.35% at December 31, 2001 .... 21,940 21,940 7.0% due 2031 .................................... 327,500 327,500 Variable due 2032, 1.5% at December 31, 2001 ..... 14,500 14,500 Variable due 2032, 1.53% at December 31, 2001 .... 10,000 10,000 -------- -------- 387,433 387,563 -------- -------- Less: Unamortized debt discount (a) ........................ 3,073 3,197 -------- -------- Long-term debt, net .............................. $684,360 $684,366 ======== ======== - ---------- (a) Debt discount and expenses are being amortized over the remaining lives of each issue. Maturities of long-term debt as of December 31, 2001 are as follows: Principal Amount ---------------- As of December 31, (In Thousands) ------------------ 2002 ................... $ -- 2003 ................... 135,000 2004 ................... -- 2005 ................... 65,000 2006 ................... 100,000 Thereafter ............. 384,360 -------- $684,360 ======== 50
10. INCOME TAXES Income tax expense is composed of the following components at December 31: 2001 2000 1999 -------- -------- -------- (In Thousands) Currently payable: Federal .................................. $ 26,373 $ 38,754 $ 38,710 State .................................... 6,098 9,683 9,453 Deferred: Federal .................................. (20,376) (9,837) (8,531) State .................................... (2,323) (1,388) (1,407) Investment tax credit amortization ......... (2,852) (3,237) (3,238) -------- -------- -------- Total ................................. 6,920 33,975 34,987 Less taxes classified in: Cumulative effect of accounting change ... 8,520 -- -- -------- -------- -------- Total income tax expense ................... $ (1,600) $ 33,975 $ 34,987 ======== ======== ======== Under SFAS No. 109, "Accounting for Income Taxes," temporary differences gave rise to deferred tax assets ad deferred tax liabilities as follows at December 31: December 31, ---------------------- 2001 2000 -------- -------- (In Thousands) Deferred tax assets: Deferred gain on sale-leaseback ................. $ 76,806 $ 82,013 Disallowed plant costs .......................... 16,650 17,758 General business credit carryforward ............ 7,741 3,635 Accrued liabilities ............................. 6,606 4,749 Other ........................................... 25,914 22,084 -------- -------- Total deferred tax assets ..................... $133,717 $130,239 ======== ======== Deferred tax liabilities: Accelerated depreciation ........................ $361,945 $369,765 Acquisition premium ............................. 266,580 274,579 Deferred future income taxes .................... 174,354 151,842 Investment tax credits .......................... 53,908 56,759 Other ........................................... 2,604 13,730 -------- -------- Total deferred tax liabilities ................ $859,391 $866,675 ======== ======== Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows: December 31, -------------------- 2001 2000 -------- ------ (In Thousands) Current deferred tax assets, net ................... $ 1,002 $ -- Current deferred tax liabilities, net .............. -- 11,980 Non-current deferred tax liabilities, net .......... 726,676 724,456 -------- -------- Net deferred tax liabilities ....................... $725,674 $736,436 ======== ======== 51
In accordance with various rate orders, we have not yet collected through rates certain accelerated tax deductions, which have been passed on to customers. As management believes it is probable that the net future increases in income taxes payable will be recovered from customers, it has recorded a deferred asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. This liability is classified above as deferred future income taxes. The effective income tax rates set forth below are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective tax rates and the federal statutory income tax rates are as follows: For the Year Ended December 31, ------------------------------- 2001 2000 1999 ---- ---- ---- Effective income tax rate ..................... (5)% 28% 29% Effect of: State income taxes ......................... (4) (4) (4) Amortization of investment tax credits ..... 8 3 3 Corporate-owned life insurance policies .... 35 9 7 Accelerated depreciation flow through and amortization, net ..................... (10) (4) (2) Other ...................................... 11 3 2 --- --- --- Statutory federal income tax rate ............. 35% 35% 35% === === === 11. COMMITMENTS AND CONTINGENCIES Municipalization Efforts by Wichita In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace us as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize our Wichita electric facilities, the City of Wichita would be required to purchase our facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize our retail electric utility business in Wichita. We will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. Our franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, we will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 51% of our total energy sales. Purchase Orders and Contracts As part of our ongoing operations and construction program, we have commitments under purchase orders and contracts, excluding fuel (which is discussed below under "- Fuel Commitments,") that have an unexpended balance of approximately $6.0 million (our share) at December 31, 2001. Manufactured Gas Sites We have been associated with three former manufactured gas sites located in Kansas that may contain coal tar and other potentially harmful materials. We and the Kansas Department of Health and Environment (KDHE) 52
entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow us to investigate these sites and set remediation priorities based on the results of the investigations and risk analysis. At December 31, 2001, the costs incurred for preliminary site investigation and risk assessment have been minimal. Clean Air Act We must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. Material capital expenditures have not been required to meet Phase II sulfur dioxide and nitrogen oxide requirements. Nuclear Decommissioning We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs that consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000. Decommissioning costs are currently being charged to operating expense in accordance with the prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%. Our investment in the decommissioning fund, including reinvested earnings, is recorded at fair value and approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. Storage of Spent Nuclear Fuel 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 the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation produced for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales. A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025. 53
Asset Retirement Obligations In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset. The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time. Nuclear Insurance The Price-Anderson Act, originally passed by Congress in 1957 and most recently amended in 1988, requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $200 million. If this amount is not sufficient to cover claims arising from an accident, the second level - Secondary Financial Protection - applies. For the second level, each licensed nuclear unit must pay a retroactive premium equal to its proportionate share of the excess loss, up to a maximum of $88.1 million per unit per accident. Currently, 106 nuclear units are participating in the Secondary Financial Protection program - 103 operating units and three closed units that still handle used nuclear fuel. The number of units participating in the program will be reduced as decommissioned units apply for and receive exemptions. Nuclear power plants provide a total of $9.5 billion in insurance coverage to compensate the public in the event of a nuclear accident. Taxpayers and the federal government pay nothing for this coverage. The Nuclear Regulatory Commission (NRC) was required to submit a report to Congress, which was submitted in September 1998 and describes the benefits that the act provides to the public. It also recommends that the act be extended for an additional ten years. The DOE submitted a report to Congress in March 1999, recommending renewal of the act. Bipartisan legislation was introduced in the 106th Congress in the Senate providing a simple renewal of Price-Anderson based on the DOE and NRC reports. The nuclear industry supports such a legislative approach for consideration early in the 107th Congress. Unless Congress renews the Price-Anderson Act, it will expire in part on August 1, 2002 as follows: . The only part of Price-Anderson that expires on August 1, 2002, is the authority of the NRC and the DOE to enter into new indemnity agreements after that date. Existing indemnity agreements would continue in full force and effect. . Without renewal, new nuclear power plants could not be covered, nor could new DOE contracts have the indemnity provision (including the proposed high-level radioactive waste disposal site in Yucca Mountain, Nevada). The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. However, on February 2, 2002, the United States Senate announced that it is considering discontinuing the federal insurance provision. The Wolf Creek owners have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the NRC. Under this plan, the owners are jointly and severally subject to a retrospective assessment of up to $88.1 million in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based 54
on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million in retrospective assessments per incident, per year. The owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion our share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund. The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, we may be subject to retrospective assessments under the current policies of approximately $10.7 million per year. Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on our financial condition and results of operations. Fuel Commitments To supply a portion of the fuel requirements for our generating plants, we have entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 2001, WCNOC's nuclear fuel commitments (our share) were approximately $3.2 million for uranium concentrates expiring in 2003, $0.6 million for conversion expiring in 2003, $22.7 million for enrichment expiring at various times through 2006 and $57.5 million for fabrication through 2025. At December 31, 2001, our coal and coal transportation contract commitments in 2001 dollars under the remaining terms of the contracts were approximately $484.1 million. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013. At December 31, 2001, our natural gas transportation commitments in 2001 dollars under the remaining terms of the contracts were approximately $1.4 million. The natural gas transportation contracts provide firm service to several of our gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016. Energy Act As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. Our portion of the assessment for Wolf Creek is approximately $9.6 million, payable over 15 years. Such costs are recovered through the ratemaking process. 12. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES PNM Transaction On November 8, 2000, Western Resources entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire Western Resources' electric utility businesses (including us) in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and Western Resources are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. At the same time Western Resources entered into the agreement with PNM, Western 55
Resources and Westar Industries, a wholly owned subsidiary of Western Resources, entered into an Asset Allocation and Separation Agreement, which provided for a split-off of Westar Industries and related matters. On October 12, 2001, PNM filed a lawsuit against Western Resources in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the KCC orders discussed below and other KCC orders reducing rates for Western Resources' electric utility businesses. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, Western Resources filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of Western Resources' electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, Western Resources filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to Western Resources purporting to terminate the merger in accordance with the terms of the merger agreement. Western Resources has notified PNM that it believes the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. Western Resources intends to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, Western Resources believes the closing of the proposed merger is not likely. KCC Proceedings and Orders The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of Western Resources' electric utility businesses (including us) from its non-utility businesses, including the rights offering, and other aspects of its unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving Western Resources' unregulated businesses are consistent with its obligation to provide efficient and sufficient electric service at just and reasonable rates to its electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement Western Resources entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by Western Resources to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by Western Resources' unregulated businesses and whether they should continue to be affiliated with its electric utility business, and Western Resources' present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Western Resources from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting Western Resources and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed Western Resources and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in Western Resources' capital structure applicable to its electric utility operations, which has the effect of prohibiting it from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed Western Resources to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of its non-utility businesses. In its order, the KCC also acknowledged that Western Resources and we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. Western Resources appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not 56
final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that Western Resources and the KCC staff make filings addressing whether the filing of applications by Western Resources and us at FERC, seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that Western Resources not increase the share of debt in its capital structure applicable to its electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC staff filed a motion to intervene in the proceeding at FERC asserting the same position. Western Resources is unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing Western Resources' and our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on Western Resources' or our ability to refinance indebtedness maturing in the next several years. Western Resources' or our inability to refinance existing indebtedness on a secured basis would likely increase borrowing costs and adversely affect liquidity and Western Resources' and our results of operations. The Financial Plan The July 20, 2001 KCC order directed Western Resources to present a financial plan to the KCC. Western Resources presented a financial plan to the KCC on November 6, 2001, which it amended on January 29, 2002. The principal objective of the financial plan is to reduce Western Resources' total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that Western Resources will proceed with the rights offering and that, in the event that the PNM merger and related split-off do not close, Western Resources will use its best efforts to sell its share of Westar Industries common stock, or shares of its common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. Western Resources is unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take. 13. LEGAL PROCEEDINGS We are involved in various other legal, environmental and regulatory proceedings. Management believes that adequate provision has been made and accordingly believes that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations. See also Notes 11 and 12 for discussion of the City of Wichita's municipalization efforts, the PNM lawsuits and the KCC regulatory proceedings. 57
14. LEASES At December 31, 2001, we had leases covering various property and equipment. Rental payments for operating leases ranging from 1 to 17 years and estimated rental commitments are as follows: LaCygne 2 Total Year Ended December 31, Lease (a) Leases - ----------------------- --------- ------ (In Thousands) Rental payments: 1999.................................... $ 34,598 $ 43,827 2000.................................... 34,598 42,559 2001.................................... 34,598 44,007 Future commitments: 2002.................................... $ 34,598 $ 41,984 2003.................................... 39,420 46,090 2004.................................... 34,598 40,798 2005.................................... 38,013 43,655 2006.................................... 42,287 47,929 Thereafter.............................. 422,318 452,275 --------- -------- Total future commitments............. $ 611,234 $672,731 ========= ======== - ---------- (a) LaCygne 2 lease amounts are included in total leases. In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operation and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the initial lease term. In 1992, we deferred costs associated with the refinancing of the secured facility bonds of the Trustee and owner of LaCygne 2. These costs are being amortized over the life of the lease and are included in operating expense. 15. RELATED PARTY TRANSACTIONS Our cash management function, including cash receipts and disbursements, is performed by Western Resources. An intercompany account is used to record net receipts and disbursements between KGE and Western Resources and KGE and WR Receivables Corporation. The net amount receivable from affiliates approximated $17.3 million at December 31, 2001 and $53.1 million at December 31, 2000 as reflected in our consolidated balance sheets. All employees we utilize are provided by Western Resources. Certain operating expenses have been allocated to us from Western Resources. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other appropriate factors. Management believes such allocation procedures are reasonable. During 2001, we declared dividends to Western Resources of $100 million. During the fourth quarter of 2001, we entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One, a subsidiary of Westar Industries, which is a wholly owned subsidiary of Western Resources for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings. 58
16. SEGMENTS OF BUSINESS In 1998, we adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires us to define and report our business segments based on how management currently evaluates its business. We have segmented our business according to differences in products and services, production processes, and management responsibility. Based on this approach, we have identified two reportable segments: Electric Operations and Nuclear Generation. Electric operations involve the production, transmission and distribution of electric power for sale to approximately 293,000 retail and wholesale customers in Kansas. Nuclear generation represents our 47% ownership in the Wolf Creek nuclear generating facility. This segment has only internal sales because it provides all of its power to its co-owners. The accounting policies of the segments are substantially the same as those described in Note 2, "Summary of Significant Accounting Policies." Segment performance is based on earnings before interest and taxes (EBIT). We have no single external customer from whom we receive ten percent or more of our revenues. Year Ended December 31, 2001: - ---------------------------- Electric Nuclear Eliminating Operations(a) Generation Items Total ------------- ---------- ----------- ---------- External sales .............................. $ 673,125 $ -- $ -- $ 673,125 Internal sales .............................. -- 117,659 (117,659) -- Depreciation and amortization ............... 64,090 41,046 -- 105,136 Earnings (loss) before interest and taxes and cumulative effect of accounting change ... 104,390 (19,078) -- 85,312 Interest expense ............................ 49,611 Earnings before income taxes ................ 35,701 Additions to property, plant and equipment .. 55,402 27,349 -- 82,751 Identifiable assets ......................... 1,887,482 1,042,563 -- 2,930,045 Year Ended December 31, 2000: - ---------------------------- Electric Nuclear Eliminating Operations Generation Items Total ---------- ---------- ----------- ---------- External sales .............................. $ 703,990 $ -- $ -- $ 703,990 Internal sales .............................. -- 107,770 (107,770) -- Depreciation and amortization ............... 64,242 40,052 -- 104,294 Earnings (loss) before interest and taxes ... 194,611 (24,323) -- 170,288 Interest expense ............................ 49,605 Earnings before income taxes ................ 120,683 Additions to property, plant and equipment .. 56,839 25,877 -- 82,716 Identifiable assets ......................... 1,923,756 1,064,817 -- 2,988,573 59
Year Ended December 31, 1999: - ---------------------------- Eliminating/ Electric Nuclear Reconciling Operations Generation Items Total ---------- ---------- ----------- ---------- External sales .............................. $ 638,340 $ -- $ -- $ 638,340 Internal sales .............................. -- 108,445 (108,445) -- Depreciation and amortization ............... 61,531 39,629 -- 101,160 Earnings (loss) before interest and taxes ... 193,980 (25,214) -- 168,766 Interest expense ............................ 49,518 Earnings before income taxes ................ 119,248 Additions to property, plant and equipment .. 53,538 10,036 -- 63,574 Identifiable assets ......................... 1,906,366 1,083,344 -- 2,989,710 - ---------- (a) EBIT shown above for Electric Operations does not include the unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle as discussed in Note 2. If the effect had been included, EBIT for the Electric Operations segment for the year ended December 31, 2001 would have been $125,808. 17. SUBSEQUENT EVENT Ice Storm In late January 2002, a severe ice storm swept through our service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs to be approximately $13 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. 18. QUARTERLY RESULTS (UNAUDITED) The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. First Second Third Fourth ---------- ---------- ---------- ----------- (In Thousands) 2001 Sales.................................... $ 163,993 $ 165,965 $ 206,926 $ 136,241 Income from operations................... 18,402 15,755 57,846 1,268 Net income before accounting change...... 5,097 2,928 31,845 (2,569) Net income............................... 17,995 2,928 31,845 (2,569) 2000 Sales.................................... $ 149,913 $ 164,967 $ 229,456 $ 159,654 Income from operations................... 22,067 45,706 84,668 24,417 Net income............................... 5,968 23,007 49,395 8,338 60
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K. 61
PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K The following financial statements are included herein. FINANCIAL STATEMENTS Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 2001 and 2000 Consolidated Statements of Income and Comprehensive Income, for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Cash Flows, for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Shareholder's Equity, for the years ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements REPORTS ON FORM 8-K FILED DURING THE QUARTER ENDED DECEMBER 31, 2001: None. 62
EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. All exhibits marked by an asterisk are management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3) of Form 10-K. Description 3(a) -Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K for I the year ended December 31, 1992, File No. 1-7324) 3(b) -Certificate of Merger of Kansas Gas and Electric Company into KCA I Corporation (Filed as Exhibit 3(b) to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 3(c) -By-laws as amended (Filed as Exhibit 3(c) to Form 10-K for the year I ended December 31, 1992, File No. 1-7324) 4(c) -Mortgage and Deed of Trust, dated as of April 1, 1940 to Guaranty I Trust Company of New York (now Morgan Guaranty Trust Company of New York) and Henry A. Theis (to whom W. A. Spooner is successor), Trustees, as supplemented by forty Supplemental Indentures, dated as of June 1, 1942, March 1, 1948, December 1, 1949, June 1, 1952, October 1, 1953, March 1, 1955, February 1, 1956, January 1, 1961, May 1, 1966, March 1, 1970, May 1, 1971, March 1, 1972, May 31, 1973, July 1, 1975, December 1, 1975, September 1, 1976, March 1, 1977, May 1, 1977, August 1, 1977, March 15, 1978, January 1, 1979, April 1, 1980, July 1, 1980, August 1, 1980, June 1, 1981, December 1, 1981, May 1, 1982, March 15, 1984, September 1, 1984 (Twenty-ninth and Thirtieth), February 1, 1985, April 15, 1986, June 1, 1991, March 31, 1992, December 17, 1992, August 24, 1993, January 15, 1994, March 1, 1994, April 15, 1994 and June 28, 2000, (Filed, respectively, as Exhibit A-1 to Form U-1, File No. 70-23; Exhibits 7(b) and 7(c), File No. 2-7405; Exhibit 7(d), File No. 2-8242; Exhibit 4(c), File No. 2-9626; Exhibit 4(c), File No. 2-10465; Exhibit 4(c), File No. 2-12228; Exhibit 4(c), File No. 2-15851; Exhibit 2(b)-1, File No. 2-24680; Exhibit 2(c), File No. 2-36170; Exhibits 2(c) and 2(d), File No. 2-39975; Exhibit 2(d), File No. 2-43053; Exhibit 4(c)2 to Form 10-K, for December 31, 1989, File No. 1-7324; Exhibit 2(c), File No. 2-53765; Exhibit 2(e), File No. 2-55488; Exhibit 2(c), File No. 2-57013; Exhibit 2(c), File No. 2-58180; Exhibit 4(c)3 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibit 2(e), File No. 2-60089; Exhibit 2(c), File No. 2-60777; Exhibit 2(g), File No. 2-64521; Exhibit 2(h), File No. 2-66758; Exhibits 2(d) and 2(e), File No. 2-69620; Exhibits 4(d) and 4(e), File No. 2-75634; Exhibit 4(d), File No. 2-78944; Exhibit 4(d), File No. 2-87532; Exhibits 4(c)4, 4(c)5 and 4(c)6 to Form 10-K for December 31, 1989, File No. 1-7324; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December 31, 1992, File No. 1-7324; Exhibit 4(b) to Form S-3, File No. 33-50075; Exhibits 4(c)2 and 4(c)3 to Form 10-K for December 31, 1993, File No. 1-7324; Exhibit 4(c)2 to Form 10-K for December 31, 1994, File No. 1-7324) Instruments defining the rights of holders of other long-term debt not required to be filed as exhibits will be furnished to the Commission upon request. 10(a) -LaCygne 2 Lease (Filed as Exhibit 10(a) to Form 10-K for the year I ended December 31, 1988, File No. 1-7324) 10(a) -Amendment No. 3 to LaCygne 2 Lease Agreement dated as of September I 29, 1992 (Filed as Exhibit 10(b)1 to Form 10-K for the year ended December 31, 1992, File No. 1-7324) 10(b) -Outside Directors' Deferred Compensation Plan (Filed as Exhibit I 10(c) to the Form 10-K for the year ended December 31, 1993, File No. 1-7324)* 12 -Computations of Ratio of Consolidated Earnings to Fixed Charges 23 -Consent of Independent Public Accountants, Arthur Andersen LLP 99(a) -Order on Rate Applications from The Corporation Commission of the I State of Kansas in the Matter of the Application of Kansas Gas and Electric Company for the Approval to Make Certain Changes in its Charges for Electric Service (Filed as Exhibit 99.1 to Form 10-Q for the quarter ended June 30, 2001) 99(b) -Press release issued August 13, 2001 by PNM announcing that talks I to modify Western Resources' transaction with PNM have been discontinued (Filed as Exhibit 99.2 to Form 10-Q for the quarter ended June 30, 2001) 99(c) -Press release issued August 13, 2001 by Western Resources I responding to PNM's announcement of discontinued talks (Filed as Exhibit 99.3 to Form 10-Q for the quarter ended June 30, 2001) 63
99(d) -Letter to the SEC of assurances given by Arthur Andersen LLP regarding their audit of December 31, 2001 financial statements to the Company 64
SIGNATURE Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KANSAS GAS AND ELECTRIC COMPANY Date: April 1, 2002 By: /s/ Caroline A. Williams ---------------------- -------------------------------------- Caroline A. Williams, President SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: Signature Title Date --------- ----- ---- /s/ CAROLINE A. WILLIAMS President (Principal Executive April 1, 2002 - ------------------------- Officer) and Director (Caroline A. Williams) /s/ PAUL R. GEIST Vice President, Treasurer April 1, 2002 - ------------------------- and Director (Principal (Paul R. Geist) Financial and Accounting Officer) /s/ MARILYN B. PAULY Director April 1, 2002 - ------------------------- (Marilyn B. Pauly) /s/ RICHARD D. SMITH Director April 1, 2002 - ------------------------- (Richard D. Smith) 65
Exhibit 12 KANSAS GAS AND ELECTRIC COMPANY Computations of Ratio of Earnings to Fixed Charges (Dollars in Thousands) Year Ended December 31, -------------------------------------------------------- 2001 2000 1999 1998 1997 -------- -------- -------- -------- -------- Earnings from continuing operations ............... $ 35,701 $120,683 $119,248 $148,736 $ 69,536 -------- -------- -------- -------- -------- Fixed Charges: Interest expense .................... 48,245 50,612 49,518 49,358 50,450 Interest on Corporate-owned Life Insurance Borrowings 44,062 39,444 31,450 32,368 31,253 Interest Applicable to Rentals .......................... 21,189 22,574 24,626 25,106 25,143 -------- -------- -------- -------- -------- Total Fixed Charges ........... 113,496 112,630 105,594 106,832 106,846 -------- -------- -------- -------- -------- Earnings (a) ............................. $149,197 $233,313 $224,842 $255,568 $176,382 ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges ............................. 1.31 2.07 2.13 2.39 1.65 (a) Earnings are deemed to consist of earnings from continuing operations and fixed charges. Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense, and the portion of rental expense which represents an interest factor.
EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into the Company's previously filed Registration Statement File No. 33-50075 of Kansas Gas and Electric Company on Form S-3. ARTHUR ANDERSEN LLP Kansas City, Missouri, March 27, 2002
Exhibit 99(d) March 27, 2002 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Arthur Andersen LLP has represented to us that the audit of Kansas Gas and Electric Company for the year ended December 31, 2001, was subject to Arthur Andersen's quality control system for the U.S. accounting and auditing practice to provide reasonable assurance that the engagement was conducted in compliance with professional standards and that there was appropriate continuity of Arthur Andersen personnel working on audits and availability of national office consultation, and the availability of personnel at foreign affiliates of Arthur Andersen to conduct the relevant portions of the audit. KANSAS GAS AND ELECTRIC COMPANY Date: March 27, 2002 By: /s/ PAUL R. GEIST ------------------------ ------------------------------------- Paul R. Geist Senior Vice President and Treasurer