SEC Filing | Evergy, Inc.

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, 1998 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 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 of (I.R.S. Employer incorporation or organization) Identification No.) P.O. BOX 208, WICHITA, KANSAS 67201 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code 316/261-6611 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 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. Common Stock, No par value 1,000 Shares (Title of each class) (Outstanding at March 31, 1999) Indicated 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 Registrant meets the conditions of General Instruction J(1)(a) and (b) to Form 10-K for certain wholly-owned subsidiaries and is therefore filing an abbreviated form. 2 KANSAS GAS AND ELECTRIC COMPANY FORM 10-K December 31, 1998 TABLE OF CONTENTS Description Page PART I Item 1. Business 3 Item 2. Properties 13 Item 3. Legal Proceedings 14 Item 4. Submission of Matters to a Vote of Security Holders 14 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 15 Item 6. Selected Financial Data 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 32 Item 8. Financial Statements and Supplementary Data 33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 54 PART III Item 10. Directors and Executive Officers of the Registrant 55 Item 11. Executive Compensation 56 Item 12. Security Ownership of Certain Beneficial Owners and Management 56 Item 13. Certain Relationships and Related Transactions 56 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 57 Signatures 60 3 PART I ITEM 1. BUSINESS GENERAL Kansas Gas and Electric Company (the company, KGE) is an electric public utility engaged in the generation, transmission, distribution and sale of electric energy in southeastern Kansas including the Wichita metropolitan area. We are a wholly-owned subsidiary of Western Resources, Inc. (Western Resources). We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Our corporate headquarters are located in Wichita, Kansas. We have no gas properties. At December 31, 1998, we had no employees. All employees are provided by our parent company, Western Resources. On February 7, 1997, Western Resources signed a merger agreement with Kansas City Power & Light Company (KCPL) by which KCPL would be merged with and into Western Resources in exchange for Western Resources common stock. In December 1997, representatives of Western Resources' financial advisor indicated that they believed it was unlikely that they would be in a position to issue a fairness opinion required for the merger on the basis of the previously announced terms. On March 18, 1998, Western Resources and KCPL agreed to a restructuring of their February 7, 1997, merger agreement which will result in the formation of Westar Energy, a new electric company. Under the terms of the merger agreement, the electric utility operations of Western Resources will be transferred to the company, and KCPL and the company will be merged into NKC, Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive Western Resources common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of Western Resources common stock received may not exceed $30.00, and one share of Westar Energy common stock per KCPL share. The Western Resources Index Price is the 20 day average of the high and low sale prices for Western Resources common stock on the NYSE ending ten days prior to closing. If the Western Resources Index Price is less than or equal to $29.78 on the fifth day prior to the effective date of the combination, either party may terminate the agreement. Upon consummation of the combination, Western Resources will own approximately 80.1% of the outstanding equity of Westar Energy and KCPL shareholders will own approximately 19.9%. As part of the combination, Westar Energy will assume all of the electric utility related assets and liabilities of Western Resources, KCPL, and the company. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of Western Resources and the company, and $800 million of debt of KCPL. Long-term debt of Western Resources, excluding Protection One, Inc. (a subsidiary of Western Resources), and the company was $2.5 billion at December 31, 1998. Under the terms of the merger agreement, it is intended that Western Resources will be released from its obligations with respect to the company's debt to be assumed by Westar Energy. For additional information concerning the company's long-term debt and obligations under the La 4 Cygne sale leaseback arrangements which will become obligations of Westar Energy, see Note 5 and Note 6 of Notes to Financial Statements. Consummation of the merger is subject to customary conditions. On July 30, 1998, Western Resources' shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. Western Resources estimates the transaction to close in 1999, subject to receipt of all necessary approvals from regulatory and government agencies. In testimony filed in February 1999, the Kansas Corporation Commission (KCC) staff recommended the merger be approved but with conditions which Western Resources believes would make the merger uneconomical. The KCC is under no obligation to accept the KCC staff recommendation. In addition, legislation has been proposed in Kansas that could impact the transaction. Western Resources does not anticipate the proposed legislation to pass in its current form. Western Resources is not able to predict whether any of these initiatives will be adopted or their impact on the transaction, which could be material. On August 7, 1998, Western Resources and KCPL filed an amended application with the Federal Energy Regulatory Commission (FERC) to approve the Western Resources/KCPL merger and the formation of Westar Energy. Western Resources has received procedural schedule orders in Kansas and Missouri. These schedules indicate hearing dates beginning May 3, 1999 in Kansas and July 26, 1999 in Missouri. KCPL is a public utility company engaged in the generation, transmission, distribution, and sale of electricity to customers in western Missouri and eastern Kansas. KCPL, Western Resources, and the company have joint interests in certain electric generating assets, including Wolf Creek. For additional information, see "Financing" below, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 13 of Notes to Financial Statements. The United States electric utility industry is evolving from a regulated monopolistic market to a competitive marketplace. The 1992 Energy Policy Act began deregulating the electricity industry. 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. A wholesale sale is defined as a utility selling electricity to a "middleman", usually a city or its utility company, to resell to the ultimate retail customer. As part of the 1992 acquisition of the company by Western Resources, we agreed to open access of our transmission system for wholesale transactions. In 1996, FERC issued order 888 and 889 requiring all jurisdictional utilities to open their transmission systems to all market participants on a nondiscriminatory basis and to split their generation market functions away from their transmission operations. As required by this order we have completed this split. For discussion regarding competition in the electric utility industry and the potential impact on the company, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 5 Discussion of other factors affecting the company are set forth in the Notes to Financial Statements and Management's Discussion and Analysis included herein. SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 14 of the Notes to Financial Statements included herein. ELECTRIC OPERATIONS General We supply electric energy at retail to approximately 283,000 customers in 147 communities in Kansas. We also supply electric energy to 27 communities and 1 rural electric cooperative, and have contracts for the sale, purchase or exchange of electricity with other utilities at wholesale. Our electric energy deliveries for the last five years were as follows: 1998 1997 1996 1995 1994 (Thousands of MWH) Residential 2,784 2,490 2,503 2,385 2,384 Commercial 2,383 2,211 2,186 2,095 2,068 Industrial 3,569 3,518 3,501 3,542 3,371 Wholesale and Interchange 1,541 2,101 2,706 1,292 1,590 Other 45 45 45 45 45 Total 10,322 10,365 10,941 9,359 9,458 Our electric sales for the last five years were as follows: 1998 1997 1996 1995 1994 (Dollars in Thousands) Residential $237,571 $214,719 $226,456 $221,628 $220,067 Commercial 170,473 162,913 176,963 171,654 167,499 Industrial 167,331 165,614 175,420 182,930 181,119 Wholesale and Interchange 50,634 53,343 57,242 31,143 38,750 Other 22,370 17,856 18,489 16,813 12,458 Total $648,379 $614,445 $654,570 $624,168 $619,893 Capacity The aggregate net generating capacity of our system is presently 2,535 megawatts (MW). The system comprises interests in twelve fossil fueled steam generating units, one nuclear generating unit (47% interest) and one diesel generator, located at seven generating stations. One of the twelve fossil fueled units (70 MW capacity) has been "mothballed" for future use (See Item 2. Properties). 6 Our 1998 peak system net load occurred on June 29, 1998 and amounted to 1,972 MW. Our net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 12% above system peak responsibility at the time of the peak. We are a member of the Southwest Power Pool (SPP). SPP's responsibility is to maintain system reliability on a regional basis. The region encompasses areas within the eight states of Kansas, Missouri, Oklahoma, New Mexico, Texas, Louisiana, Arkansas, and Mississippi. 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 system. The tariff allows for both non-firm and firm transmission access. We are a member of the Western Systems Power Pool (WSPP). Under this arrangement, electric utilities and marketers throughout the western United States have agreed to market energy. Services available include short-term and long-term economy energy transactions, unit commitment service, firm capacity and energy sales and energy exchanges. We have an agreement with Midwest Energy, Inc. (MWE), to provide MWE with peaking capacity of 61 MW through the year 2008. We also entered into an agreement with Empire District Electric Company (Empire), to provide Empire with peaking and base load capacity (20 MW in 1994 increasing to 80 MW in 2000) through the year 2000. Because the electric utility business is seasonal, the KCC has adopted the Kansas Cold Weather Rule (CWR). The CWR specifies that business procedures related to disconnection of service for residential customers have certain restrictions from November 1 through the following March 31. The CWR is intended to prevent disconnections due to customers not paying their bills, leaving the customers facing life threatening risks due to outside temperatures. Disconnections for customers who do not pay their bills can occur during this time frame under certain weather conditions. Various pay agreement rules correspond to the CWR. Due to the CWR, collection efforts for unpaid bills are much more intense from April 1 to October 31. Sales peaks correlate directly with the seasonality of the midwestern weather and, therefore, the workload for customer service is the heaviest from April through August. Future Capacity We are participating with Western Resources in the installation of three new combustion turbine generators for use as peaking units. The installed capacity of the three new generators will be 300 MW. The first two units are scheduled to be placed in operation in 2000 and the third is scheduled to be placed in operation in 2001. Western Resources estimates that the project will require $120 million in capital resources through the completion of the projects in 2001. The extent of our participation in these projects has not been determined. We are also planning to return our inactive generation plant in Neosho, Kansas to active service in 1999. 7 For further discussion regarding future capacity and cash requirements, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Fuel Mix Our coal-fired units comprise 1,120 MW of the total 2,535 MW of generating capacity and our nuclear unit provides 547 MW of capacity. Of the remaining 868 MW of generating capacity, units that can burn either natural gas or oil account for 865 MW, and the remaining unit which burns only diesel fuel accounts for 3 MW (See Item 2. Properties). During 1998, low sulfur coal was used to produce 52% of our electricity. Nuclear produced 37% and the remainder was produced from natural gas, oil, or diesel fuel. During 1999, based on our estimate of the availability of fuel, coal will be used to produce approximately 56% of our electricity and nuclear will be used to produce 30%. Our fuel mix fluctuates with the operation of nuclear powered Wolf Creek as discussed below under Nuclear Generation. Coal The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 443 MW (KGE's 20% share) (See Item 2. Properties). Western Resources, the operator of JEC, and KGE have a long-term coal supply contract with Amax Coal West, Inc. (AMAX), a subsidiary of Cyprus Amax Coal Company, to supply low sulfur coal to JEC from AMAX's Eagle Butte Mine or an alternate mine source of AMAX's Belle Ayr Mine, both located in the Powder River Basin in Campbell County, Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual delivery quantities based on MMBtu provisions. The coal to be supplied is surface mined and has an average Btu content of approximately 8,300 Btu per pound and an average sulfur content of .43 lbs/MMBtu (See Environmental Matters). The average delivered cost of coal for JEC was approximately $1.13 per MMBtu or $18.96 per ton during 1998. Coal is transported by Western Resources from Wyoming under a long-term rail transportation contract with Burlington Northern Santa Fe and Union Pacific railroads to JEC through December 31, 2013. Rates are based on net load carrying capabilities of each rail car. Western Resources provides 868 aluminum rail cars, under a 20 year lease, to transport coal to JEC. The two coal-fired units at La Cygne Station have an aggregate generating capacity of 677 MW (KGE's 50% share) (See Item 2. Properties). The operator, KCPL, maintains coal contracts as discussed in the following paragraphs. La Cygne 1 uses low sulfur Powder River Basin coal which is supplied under a variety of spot market transactions, discussed below. High Btu Kansas/Missouri coal is blended with the Powder River Basin coal and is secured from time to time under spot market arrangements. La Cygne 1 uses a blended fuel mix containing approximately 85% Powder River Basin coal. 8 La Cygne 2 and additional La Cygne 1 Powder River Basin coal is supplied through several contracts, expiring at various times through 1999. This low sulfur coal had an average Btu content of approximately 8,500 Btu per pound and a maximum sulfur content of .50 lbs/MMBtu (See Environmental Matters). Transportation is covered by KCPL through its Omnibus Rail Transportation Agreement with Burlington Northern Santa Fe Railroad and Kansas City Southern Railroad through December 31, 2000. During 1998, the average delivered cost of all local and Powder River Basin coal procured for La Cygne 1 was approximately $0.74 per MMBtu or $12.77 per ton and the average delivered cost of Powder River Basin coal for La Cygne 2 was approximately $0.66 per MMBtu or $10.97 per ton. We have entered into all of our coal contracts during the ordinary course of business and are not substantially dependent upon these contracts. We believe there are other suppliers for and plentiful sources of coal available at reasonable 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. We have entered into all of our transportation contracts during the ordinary course of business. At the time of entering into these contracts, we were not substantially dependent upon these contracts due to the availability of competitive rail options. Due to recent rail consolidation, there are now only two rail carriers capable of serving our origin coal mines and our generating stations. In the event one of these carriers became unable to provide reliable service, we could experience a short-term disruption of our business. However, due to the obligation of the remaining carriers to provide service under the Interstate Commerce Act, we do not anticipate any substantial long-term disruption of our business. Natural Gas We use natural gas as a primary fuel in our Gordon Evans, Murray Gill and Neosho Energy Centers. Natural gas for these generating stations is supplied by readily available gas from the spot market. Short-term economical spot market purchases will supply the system with the flexible natural gas supply to meet operational needs. We maintain firm natural gas transportation capacity through Williams Gas Pipelines Central for the above facilities through April 1, 2010. Oil We use oil as an alternate fuel when economical or when interruptions to natural gas make it necessary. Oil is also used as a start-up fuel at JEC and La Cygne generating stations. All of the oil we have burned during the past several years has been obtained by spot market purchases. At December 31, 1998, we had approximately one million gallons of No. 2 oil and eighteen million gallons of No. 6 oil which is believed to be sufficient to meet emergency requirements and protect against lack of availability of natural gas and/or the loss of a large generating unit. 9 Other Fuel Matters Our contracts to supply fuel for our coal 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, when the price is favorable, to take advantage of economic opportunities. Set forth in the table below is information relating to the weighted average cost of fuel that we have used. 1998 1997 1996 1995 1994 Per Million Btu: Nuclear $0.48 $0.51 $0.50 $0.40 $0.36 Coal 0.86 0.89 0.88 0.91 0.90 Gas 2.28 2.56 2.30 1.68 1.98 Oil 4.05 3.32 2.74 4.00 3.90 Cents per KWH Generation $0.94 1.00 0.93 0.82 0.89 Nuclear Generation The owners of Wolf Creek have on hand or under contract 100% of their uranium needs for 1999 and 59% of the uranium required to operate Wolf Creek through September 2003. The balance is expected to be obtained through spot market and contract purchases. We have active contracts with the following companies for uranium: Cameco Corporation and Geomex Minerals, Inc. A contractual arrangement is in place with Cameco Corporation for the conversion of uranium to uranium hexafluoride sufficient for the operation of Wolf Creek through the year 2001. We have active contracts for uranium enrichment with Urenco and USEC. Contracted arrangements cover 88% of the uranium enrichment required for operation of Wolf Creek through March 2005. The balance is expected to be obtained through spot market and term contract purchases. We have entered into all of our uranium, uranium hexaflouride and uranium enrichment arrangements during the ordinary course of business and are not substantially dependent upon these agreements. We believe there are other supplies available at reasonable prices to replace, if necessary, these contracts. In the event that we were required to replace these contracts, we would not anticipate a substantial disruption of our business. Nuclear fuel is amortized to cost of sales based on the quantity of heat produced for the generation of electricity. Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. We pay the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered and sold for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales and currently recovered through rates. 10 In 1996, a U. S. Court of Appeals issued a decision that the Nuclear Waste Policy Act unconditionally obligated the DOE to begin accepting spent fuel for disposal in 1998. In late 1997, the same court issued another decision precluding 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. By the end of 1997, WCNOC and other utilities had petitioned the DOE for authority to suspend payments of their quarterly fees until such time as the DOE begins accepting spent fuel. In January 1998, the DOE denied the petition of the utilities. In February 1998, WCNOC and other utilities petitioned the court to: 1) compel the DOE to submit to the court within 30 days a program, with appropriate milestones, to dispose of used nuclear fuel beginning immediately, 2) declare that the utilities are relieved of their obligation to pay into the Nuclear Waste Fund, and are authorized to escrow future fees unless and until DOE begins disposing of their used fuel, 3) prohibit the federal government from suspending or terminating it's disposal contracts with the utilities or from imposing any interest, penalties or other charges as a result of a utility's suspension of waste fund payments, and 4) preclude the federal government from using fees paid into the waste fund to compensate the utilities for damages or additional costs they have incurred as a result of the agency's breach of its obligation. In May 1998, the court issued an order disposing of all pending motions and petitions. 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 made clear that the court will not revisit the matter until the utilities have completed their pursuit of that remedy. WCNOC intends to pursue the appropriate contract remedy against the DOE. A permanent disposal site may not be available for the industry until 2010 or later, although an interim facility may be available earlier. 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 may not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. Under current regulatory guidelines, this facility can provide storage space until about 2005. Wolf Creek is implementing a plan to increase its on-site spent fuel storage capacity. That project, expected to be completed by 2000, should provide 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 and selected a site in northern Nebraska to locate a disposal facility. The present estimate of the cost for such a facility is about $154 million. WCNOC and the owners of the other five nuclear units in the compact have provided most of the pre-construction financing for this project. There is uncertainty as to whether this project will be completed. Significant opposition to the project has been raised by Nebraska officials and residents in the area of the proposed facility, and attempts have been made 11 through litigation and proposed legislation in Nebraska to slow down or stop development of the facility. In December 1998, the Nebraska agencies considering the developer's license application for the facility issued an order denying the application. The developer has filed for a "contested case hearing" regarding the license denial. This is the next step in appealing the agencies decision. Also in December 1998, WCNOC and other utilities that have provided pre- construction financing filed suit against the State of Nebraska, the licensing agencies and others, seeking damages related to the utilities excessive costs incurred because of the agencies delay in reaching a decision in this matter. Wolf Creek has an 18-month refueling and maintenance schedule which permits uninterrupted operation every third calendar year. Wolf Creek is scheduled to be taken off-line on April 3, 1999 for its tenth refueling and maintenance outage. During the outage electric demand is expected to be met primarily by our coal-fired generating units. Additional information with respect to insurance coverage applicable to the operations of our nuclear generating facility is set forth in Note 2 of the Notes to Financial Statements. Environmental Matters We currently hold all Federal and State environmental approvals required for the operation of our generating units. We believe we are presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA). The Federal sulfur dioxide standards applicable to the company's JEC and La Cygne 2 units, prohibit the emission of more than 1.2 pounds of sulfur dioxide per million Btu of heat input. Federal particulate matter emission standards applicable to these units prohibit: (1) the emission of more than 0.1 pounds of particulate matter per million Btu of heat input and (2) an opacity greater than 20%. Federal NOx emission standards applicable to these units prohibit the emission of more than 0.7 pounds of NOx per million Btu of heat input. The JEC and La Cygne 2 units have met: (1) the sulfur dioxide standards through the use of low sulfur coal (See Coal); (2) the particulate matter standards through the use of electrostatic precipitators; and (3) the 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 million Btu of heat input at our generating units. We have sufficient low sulfur coal under contract (See Coal) to allow compliance with such limits at La Cygne 1 for the life of the contract. All 12 facilities burning coal are equipped with flue gas scrubbers and/or electrostatic precipitators. 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. We do not expect any material capital expenditures to be required 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 2 of the Notes to Financial Statements. REGULATION AND RATES We are subject as an operating electric utility 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. We are also subject to the jurisdiction of the FERC and the KCC with respect to the issuance of our securities. Additionally, we are subject to the jurisdiction of the FERC, including jurisdiction as to rates with respect to sales of electricity for resale, and the Nuclear Regulatory Commission as to nuclear plant operations and safety. Additional information with respect to Regulation and Rates is discussed in Notes 1 and 3 of the Notes to Financial Statements and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During Past Five Years Annette M. Beck 36 Chairman of the Board Vice President, Customer (since January 1999) Service (since Oct. 1998), and President (since Director - Customer October 1998) Service (Aug 1997 to Oct 1998), and prior to that Director - Strategic Planning, Western Resources, Inc. Richard D. Terrill 44 Secretary, Treasurer and General Counsel Executive officers serve at the pleasure of the Board of Directors. There are no family relationships among any of the officers, nor any arrangements or 13 understandings between any officer and other persons pursuant to which she or he was appointed as an officer. ITEM 2. PROPERTIES We own or lease and operate an electric generation, transmission, and distribution system in Kansas. ELECTRIC FACILITIES Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (1) Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 152 2 1967 Gas--Oil 382 Jeffrey Energy Center (20%) (2): Steam Turbines 1 1978 Coal 147 2 1980 Coal 148 3 1983 Coal 148 La Cygne Station (50%) (2): Steam Turbines 1 1973 Coal 343 2 1977 Coal 334 Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 44 2 1954 Gas--Oil 74 3 1956 Gas--Oil 107 4 1959 Gas--Oil 106 Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 0 (3) Wichita Plant: Diesel Generator 5 1969 Diesel 3 Wolf Creek Generating Station (47%)(2): Nuclear 1 1985 Uranium 547 Total 2,535 (1) Based on MOKAN rating. (2) We jointly own Jeffrey Energy Center (20%), La Cygne Station (50%) and Wolf Creek Generating Station (47%). Western Resources jointly owns 64% of Jeffrey Energy Center. KCPL jointly owns 50% of La Cygne Station and 47% of Wolf Creek Generating Station. (3) This unit has been "mothballed" for future use. In 1999 we plan to return this unit to active service. 14 FINANCING Our ability to issue additional debt is restricted under limitations imposed by our Mortgage and Deed of Trust. 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 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. Based on our results for the 12 months ended December 31, 1998, approximately $1.1 billion principal amount of additional first mortgage bonds could be issued (7.0% interest rate assumed). KGE bonds may be issued, subject to the restrictions in the preceding paragraph, on the basis of property additions not subject to an unfunded prior lien and on the basis of bonds which have been retired. As of December 31, 1998, we had approximately $1.4 billion of net bondable property additions not subject to an unfunded prior lien entitling us to issue up to $1 billion principal amount of additional bonds. As of December 31, 1998, $17 million in additional bonds could be issued on the basis of retired bonds. In connection with the combination of the electric utility operations of Western Resources, KCPL and the company, Westar Energy will assume $1.9 billion of indebtedness for borrowed money of Western Resources and the company comprised primarily of the companies' outstanding long-term debt. Pursuant to the amended and restated agreement and plan of merger, the company's mortgage, by operation of law, will be assumed by Westar Energy. See, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 13 of Notes to Financial Statements. ITEM 3. LEGAL PROCEEDINGS Information on legal proceedings involving the company is set forth in Notes 2, 3, and 8 of Notes to Financial Statements included herein. See also Item 1. Business, Environmental Matters, and Regulation and Rates. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Information required by Item 4 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. 15 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock is owned by Western Resources and is not traded on an established public trading market. See Note 13 of Notes to Financial Statements for information concerning the effect on the ownership of our common stock caused by the pending transaction with KCPL. ITEM 6. SELECTED FINANCIAL DATA

16 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In Management's Discussion and Analysis we explain the general financial condition and the operating results for the company. We explain: - What factors impact our business - What our earnings and costs were in 1998 and 1997 - Why these earnings and costs differed from year to year - How our earnings and costs affect our overall financial condition - What our capital expenditures were for 1998 - What we expect our capital expenditures to be for the years 1999 through 2001 - How we plan to pay for these future capital expenditures - Any other items that particularly affect our financial condition or earnings As you read Management's Discussion and Analysis, please refer to our Statements of Income on page 35. These statements show our operating results for 1998, 1997 and 1996. In Management's Discussion and Analysis, we analyze and explain the significant annual changes of specific line items in the Statements of Income. Forward-Looking Statements Certain matters discussed here and elsewhere in this Annual Report 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" 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, litigation, rate and other regulatory matters, possible corporate restructurings, mergers, acquisitions, dispositions, liquidity and capital resources, interest and dividend rates, Year 2000 Issue, environmental matters, changing weather, nuclear operations and accounting matters. What happens in each case could vary materially from what we expect because of such things as electric utility deregulation, including ongoing state and federal activities; future economic conditions; legislative developments; our regulatory and competitive markets; and other circumstances affecting anticipated operations, sales and costs. 1998 HIGHLIGHTS We experienced warmer weather during the summer months in 1998 than we did in 1997 which improved net income by $13.1 million. The effect of our electric rate decrease lowered 1998 net income $6 million. 17 In January 1997, the Kansas Corporation Commission (KCC) entered an order reducing our electric rates. Significant terms of the order are as follows: - We made permanent the May 1996 interim $8.7 million decrease in our annual rates on February 1, 1997 - We reduced our annual rates by $36 million on February 1, 1997 - We rebated $2.3 million to our customers in January 1998 - We reduced our annual rates by an additional $10 million on June 1, 1998 - We rebated an additional $2.3 million to our customers in January 1999 - We will reduce our annual rates by an additional $10 million on June 1, 1999 These electric rate decreases have negatively impacted our net income. The total cumulative effect of these rate decreases is approximately $65 million. All rate decreases are cumulative. Rebates are one-time events and do not influence future rates. Operating Results In our "1998 Highlights", we discussed factors that most significantly changed our operating results for 1998 compared to 1997. 1998 compared to 1997: Net income of $103.8 million increased significantly from $52.1 million for 1997. The increase in net income is primarily due to increased electric sales because of warmer weather, lower operating and maintenance costs, the completion of the amortization of phase- in revenues in December 1997, and death benefits received from corporate-owned life insurance policies. 1997 compared to 1996: Net income of $52.1 million for 1997 decreased substantially from $96.3 million for 1996. The decrease in net income is primarily attributable to the implementation of a $36 million rate reduction and an $8.7 million interim rate reduction which became permanent on February 1, 1997. The following explains significant changes from prior year results in sales, cost of sales, operating expenses, other income (expense), interest expense and income taxes. Sales Sales are based on energy deliveries and rates authorized by the KCC and the Federal Energy Regulatory Commission (FERC). Rates charged for the sale and delivery of electricity are designed to recover the cost of service and allow investors a fair rate of return. Our sales vary with levels of energy deliveries. Changing weather affects the amount of energy our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand. 18 Many things will affect our future sales. They include: - The weather - Our electric rates - Competitive forces - Customer conservation efforts - Wholesale demand - The overall economy of our service area 1998 compared to 1997: Sales increased $33.9 million or six percent due to increased retail energy deliveries as a result of warmer summer temperatures. Our annual $10 million electric rate decrease implemented on June 1, 1998 and decreased wholesale energy deliveries partially offset this increase. The following table reflects the change in electric energy deliveries, as measured by kilowatt hours, for retail customers for 1998 compared to 1997: Increase Residential. . . . . . . 11.8% Commercial . . . . . . . 7.8% Industrial . . . . . . . 1.5% Total Retail . . . . . 6.3% 1997 compared to 1996: Sales decreased $40.1 million or six percent because of lower electric rates which were implemented on February 1, 1997. Reduced electric rates lowered 1997 sales by an estimated $36.8 million compared to 1996. Sales volumes to our retail customers remained virtually unchanged in 1997. Cost of Sales Items included in energy cost of sales are fuel expense and purchased power expense (electricity we purchase from others for resale). Electric fuel costs are included in base rates. Therefore, if we wished to recover an increase in fuel costs, we would have to file a request for recovery in a rate filing with the KCC which could be denied in whole or in part. Any increase in fuel costs from the projected average which the company did not recover through rates would reduce our earnings. The degree of any such impact would be affected by a variety of factors, however, and thus cannot be predicted. 1998 compared to 1997: Actual cost of fuel to generate electricity (coal, nuclear fuel, natural gas or oil) and the amount of power purchased from other utilities were $19.6 million higher in 1998 than in 1997. With an increase in customer demand for electricity and the availability of our Wolf Creek nuclear generating station and La Cygne coal generating station during 1998, we produced more electricity during 1998 than in 1997. The increase in net generation caused our fuel costs to increase during 1998. In 1998, due to warmer than normal weather throughout the Midwest and a lack of power available for purchase on the wholesale market, the wholesale power market saw extreme volatility in prices and availability. We believe future volatility, such as that recently experienced in the market, could impact our cost of power purchased. 19 1997 compared to 1996: Actual cost of fuel to generate electricity and the amount of power purchased from other utilities were $6.3 million higher in 1997 than in 1996. Our Wolf Creek nuclear generating station was off-line in the fourth quarter of 1997 for scheduled maintenance and our La Cygne coal generating station was off-line during 1997 for an extended maintenance outage. As a result, we purchased more power from other utilities and burned more natural gas to generate electricity at our facilities. Natural gas is more costly to burn than coal and nuclear fuel for generating electricity. Operating Expenses Operating and Maintenance Expense Operating and maintenance expense decreased $29.5 million in 1998 compared to 1997. The decrease was attributable to a substantial decrease in KGE's portion of costs shared with Western Resources which are associated with the dispatching of electric power. Operating and maintenance expense increased $4 million in 1997 compared to 1996. An extended maintenance outage at our La Cygne generating station accounted for most of this increase. We anticipate our operating expenses (including cost of sales) will increase in 1999 as a result of Wolf Creek being taken out of service for refueling and maintenance as discussed under Item 1. Business under "Fuel Mix". We also expect our operating and maintenance expense to increase when we bring an inactive generating plant back into active service in 1999. See LIQUIDITY AND CAPITAL RESOURCES below for further discussion of this project. Depreciation and Amortization Expense Depreciation and amortization expense decreased $24.6 million in 1998 due to the complete amortization of a regulatory asset in 1997. During 1997 we recorded $26.3 million of amortization relating to this regulatory asset. Depreciation and amortization expense increased $9.6 million in 1997 from 1996 due to the additional amortization of $8.8 million we recorded relating to phase-in revenues. Selling, General and Administrative Expense Selling, general and administrative expense increased $3 million in 1998. Storm related restoration expenses and increased labor costs contributed to the increase. In 1997 selling, general and administrative expense increased $2.9 million from 1996. Most of this increase is attributable to higher employee benefit costs. Business Segments We define and report our business segments based on how management currently evaluates our business. We are evaluated from a segment perspective as a part of our parent company, Western Resources. Our company is an 20 integral component of Western Resources and its financial position and operations are managed as such. Based on the management approach to determining business segments, our company only has one business segment. This segment is nuclear generation. Our remaining operations of fossil generation and energy delivery are fully integrated with those of Western Resources. We along with Western Resources manage our business segments' performance based on our earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by generally accepted accounting principles, nor should it be construed as an alternative to operating income. Additionally, it is indicative neither of operating performance nor cash flows available to fund the cash needs of our company. Items excluded from EBIT are significant components in understanding and assessing the financial performance of our company. We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by our company to satisfy its 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. Allocated sales are external sales collected from customers by our electric operations segment that are allocated to our nuclear generation business segment based on demand and energy cost. The following discussion identifies key factors affecting our business segment. Nuclear Generation 1998 1997 1996 (Dollars in Thousands) Allocated sales . . . . . . . . $117,517 $102,330 $100,592 Depreciation and amortization . 39,583 65,902 57,242 EBIT. . . . . . . . . . . . . . (20,920) (60,968) (51,585) Nuclear fuel generation has no external sales because it provides all of its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc. The amounts above are our 47% share of Wolf Creek's operating results. Allocated sales and EBIT were higher in 1998 because Wolf Creek operated the entire year without any outages. In 1997, the Wolf Creek facility was off line for 58 days for a scheduled maintenance outage. Depreciation and amortization expense for 1998 compared to 1997 decreased $26 million because we had fully amortized a regulatory asset during 1997. This decrease in amortization expense increased EBIT for 1998. Decommissioning: Decommissioning is a nuclear industry term for the permanent shut-down of a nuclear power plant when the plant's license expires. The Nuclear Regulatory Commission (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 power plants to prepare formal financial plans. These plans ensure that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant. 21 The Financial Accounting Standards Board is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur: - Our annual decommissioning expense could be higher than in 1998 - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant We do not believe that such changes, if required, would adversely affect our operating results due to our current ability to recover decommissioning costs through rates (see Note 2). 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 which 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 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to operations. Reasons for discontinuing SFAS 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred and a significant change by regulators from a cost-based rate regulation to another form of rate regulation. We periodically review SFAS 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS 71 accounting treatment based upon competitive or other events, we may significantly impact the value of our net regulatory assets and our utility plant investments, particularly the Wolf Creek nuclear generation facility (Wolf Creek). See OTHER INFORMATION for initiatives taken to restructure the electric industry in Kansas. Regulatory changes, including competition, could adversely impact our ability to recover our investment in these assets. As of December 31, 1998, we have recorded regulatory assets which are currently subject to recovery in future rates of approximately $261 million. Of this amount, $176 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 that include coal contract settlement costs, deferred plant costs and debt issuance costs. In a competitive environment, 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. 22 Other Income (Expense) Other income (expense) includes miscellaneous income and expenses not directly related to our operations. Other income (expense) increased $12.7 million in 1998 as compared to 1997. The increase is primarily attributable to benefits received during 1998 pursuant to our corporate-owned life insurance policies totaling $13.7 million. Other income (expense) for 1997 declined $7.7 million from 1996. The decrease is primarily due to income and expenses relating to our corporate-owned life insurance policies. Interest Expense Interest expense includes the interest we paid on outstanding debt. In 1998 interest expense on short-term debt decreased $1 million. We repaid our outstanding short-term debt balance during January 1998. After January 1998, no short-term debt was held. Our average short-term debt balance during 1998 was $0.6 million compared to $22.9 million during 1997. The interest we paid on long-term debt remained virtually unchanged. We recognized a $7.4 million decrease in short-term debt interest in 1997 compared to 1996. During 1997 we held a smaller average short-term debt balance than in 1996. Income Taxes Income taxes increased $27.6 million in 1998 as compared to 1997 as a result of the substantial increase in our 1998 net income. Income taxes decreased $18.9 million in 1997 as compared to 1996. The decrease is primarily due to the decrease we recognized in 1997 net income. LIQUIDITY AND CAPITAL RESOURCES Overviews Our cash requirements consist of capital expenditures and maintenance program costs designed to improve facilities which 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. At December 31, 1998, we had no short-term borrowings compared to $45 million at December 31, 1997. Other funds are available to us from the sale of securities we register for sale with the Securities and Exchange Commission (SEC). As of December 31, 1998, $50 million of KGE first mortgage bonds were registered. The embedded cost of long-term debt was 7.2% and 7.3% at December 31, 1998 and 1997. 23 Capital Structure Our capital structures at December 31, 1998, and 1997 were as follows: 1998 1997 Common Stock . . . . . . . . 62% 62% Long-term Debt . . . . . . . 38% 38% Total. . . . . . . . . . . . 100% 100% Security Ratings Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and Moody's Investors Service (Moody's) are independent credit-rating agencies. These agencies rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest, dividends and principal on these securities. These ratings affect how much we will have to pay as interest or dividends on securities we sell to obtain additional capital. The better the rating, the less we will have to pay on debt securities we sell. At December 31, 1998, ratings with these agencies were as follows: Mortgage Bond Rating Agency Rating S&P BBB+ Fitch A- Moody's A3 Following the announcement of Western Resources restructed merger agreement with KCPL, S&P placed its ratings of Western Resources and the company on CreditWatch with positive implications. Future Cash Requirements We believe that internally generated funds and new credit agreements will be sufficient to meet our operating and capital expenditure requirements and debt service payments through the year 2001. Uncertainties affecting our ability to meet these requirements with internally generated funds include the effect of competition and inflation on operating expenses, sales volume, regulatory actions, compliance with future environmental regulations, the availability of generating units and weather. The amount of these requirements and our ability to fund them will also be significantly impacted by the pending combination of Western Resources electric utility operations, KCPL and the company. We are participating with Western Resources in the installation of three new combustion turbine generators for use as peaking units. The installed capacity of the three new generators will be 300 MW. The first two units are scheduled to be placed in operation in 2000 and the third is scheduled to be placed in operation in 2001. Western Resources estimates that the project will require $120 million in capital resources through the completion of the projects in 2001. The extent of our participation in these projects has not been determined. We are also planning to return our inactive generation plant in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7 million. 24 Our business requires a significant capital investment. We currently expect that through the year 2001, we will need cash mostly for ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. Capital expenditures for 1998 and anticipated capital expenditures for 1999 through 2001 are as follows: Electric Nuclear Operations Generation Total (Dollars in Thousands) 1998. . . . . . . . . . $51,600 $25,800 $77,400 1999. . . . . . . . . . 61,000 19,700 80,700 2000. . . . . . . . . . 61,200 32,200 93,400 2001. . . . . . . . . . 60,600 21,200 81,800 These estimates are prepared for planning purposes and may be revised. Actual expenditures may differ from our estimates. These expenditures do not take into account the pending combination of Western Resources electric utility operations, KCPL and the company. Acquisition Adjustment Implementation In accordance with the 1992 KCC merger order relating to the acquisition of Kansas Gas and Electric Company by Western Resources, amortization of the acquisition adjustment commenced August 1995. The amortization will amount to approximately $20 million (pre-tax) per year for 40 years. We and Western Resources (combined companies) are recovering the amortization of the acquisition adjustment through cost savings under a sharing mechanism approved by the KCC. Based on the order issued by the KCC, with regard to the recovery of the acquisition premium, the combined companies must achieve a level of savings on an annual basis (considering sharing provisions) of approximately $27 million in order to recover the entire acquisition premium. On January 15, 1997, the KCC fixed the annual merger savings level at $40 million which provides complete recovery of the acquisition premium amortization expense and a return on the acquisition premium. See Note 3 for further information relating to rate matters and regulation. As Western Resources' management presently expects to continue this level of savings, the amount is expected to be sufficient to allow for the full recovery of the acquisition premium. 25 OTHER INFORMATION Competition and Enhanced Business Opportunities The United States electric utility industry is evolving from a regulated monopolistic market to a competitive marketplace. The 1992 Energy Policy Act began deregulating the electricity industry. 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. A wholesale sale is defined as a utility selling electricity to a "middleman", usually a city or its utility company, to resell to the ultimate retail customer. As part of the 1992 merger, 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 to ourselves. During 1998, wholesale electric sales represented approximately 8% of total electric sales. Various states have taken steps to allow retail customers to purchase electric power from providers other than their local utility company. The Kansas Legislature created a Retail Wheeling Task Force (the Task Force) in 1997 to study the effects of a deregulated and competitive market for electric services. Legislators, regulators, consumer advocates and representatives from the electric industry made up the Task Force. Several bills were introduced to the Kansas Legislature in the 1998 legislative session, but none passed. Hearings on retail wheeling bills are being held in the 1999 legislature. The outcome of retail wheeling legislature in Kansas remains uncertain. Increased competition for retail electricity sales may reduce future electric utility earnings compared to our historical electric utility earnings. After all ordered electric rate decreases are implemented, our rates will be at 90% of the national average for retail customers. Because of these reduced rates, we expect to retain a substantial part of our current volume of energy deliveries in a competitive environment. While operating in this competitive environment may place pressure on our profit margins and credit ratings, we expect it to create opportunities. Wholesale and industrial customers may pursue cogeneration, self-generation, retail wheeling, municipalization or relocation to other service territories in an attempt to cut their energy costs. Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition. We offer competitive electric rates for industrial improvement projects and economic development projects in an effort to maintain and increase electric load. Year 2OOO Issue We, as part of the Western Resources Year 2000 readiness program, are currently addressing the effect of the Year 2000 Issue on information systems and operations. We face the Year 2000 Issue because many computer systems and applications abbreviate dates by eliminating the first two digits of the year, assuming that these two digits are always "19". On January 1, 2000, some computer programs may incorrectly recognize the date as January 1, 1900. Some computer systems and applications may incorrectly process critical information 26 or may stop processing altogether because of the date abbreviation. Calculations using dates beyond December 31, 1999 may affect computer applications before January 1, 2000. We have recognized the potential adverse effects the Year 2000 Issue could have on our company. The company shares information and computer systems with Western Resources. In 1996, we established a formal Year 2000 readiness program to investigate and correct these problems in the main computer systems of our company. In 1997, we expanded the program to include all departments and business units of our company, using a common methodology. The Year 2000 issues concerning the Wolf Creek nuclear operating plant are discussed under WCNOC below. The goal of our Year 2000 readiness program is to identify and assess all critical computer programs, computer hardware and embedded systems potentially affected by the Year 2000 date change, to repair or replace those systems found to be incompatible with Year 2000 dates, and to develop predetermined actions to be used as contingencies in the event any critical business function fails unexpectedly or is interrupted. The program is directed by a written policy which provides the guidance and methodology to the departments and business units to follow. Due to varying degrees of exposure of departments and business units to the Year 2000 Issue, some departments and business units are further along in their readiness efforts than others. All departments have completed the awareness, inventory, and assessment phases, and have developed their initial contingency plans. Several smaller departments and business units have completed the assessment, remediation, and testing phases. The majority of our current efforts are in the remediation and testing phases. Overall, based on manhours as a measure of work effort, Western Resources believes it is approximately 74% complete with its readiness efforts. The estimated progress of Western Resources departments and business units, exclusive of WCNOC, at December 31, 1998, based on manhours, is as follows: Percentage Department/Business Unit Completion Fossil Fuel . . . . . . . . . . . . . . 81% Power Delivery. . . . . . . . . . . . . 73% Information Technology. . . . . . . . . 76% Administrative. . . . . . . . . . . . . 69% Our Year 2000 readiness program addresses all Information Technology (IT) and non-IT issues which may be impacted by the Year 2000 Issue. We have included commercial computer software, including mainframe, client/server, and desktop software; internally developed computer software, including mainframe, client/server, and desktop software; computer hardware, including mainframe, client/server, desktop, network, communications, and peripherals; devices using embedded computer chips, including plant equipment, controls, sensors, facilities equipment, heating, ventilating, and air conditioning (HVAC) equipment; and relationships with third-party vendors, suppliers, and customers. Our program requires testing as a method for verifying the Year 2000 readiness of an item. For those items which are impossible to test, 27 other methods are being used to identify the readiness status, provided adequate contingency plans are established to provide a workaround or backup for the item. Our Year 2000 readiness efforts were substantially completed by the end of 1998 except for those items scheduled for normal maintenance or upgrade during 1999. Western Resources currently estimates that total costs to update all of its electric utility operating systems for Year 2000 readiness, excluding costs associated with WCNOC discussed below, to be approximately $7 million, of which $4.2 million represents IT costs and $2.8 million represents non-IT costs. As of December 31, 1998 Western Resources has expensed approximately $4.1 million of these costs, of which $3.2 million represent IT costs and $0.9 million represent non-IT costs. Based on what they know, they expect to incur the remaining $2.9 million, of which $1 million represents IT costs and $1.9 million represents non-IT costs, by the end of 1999. These costs include labor costs for both Western Resources' employees and contract personnel used in our Year 2000 program, and non-labor costs for software tools used in our remediation and testing efforts, replacement software, replacement hardware, replacement embedded devices, and miscellaneous costs associated with their testing and replacement. Western Resources has allocated approximately $1.6 million of the expensed costs to our company and we expect an additional $1.2 million to be allocated for the remaining costs to be incurred. We have identified the following major areas of risk relating to our Year 2000 Issue exposure: 1) vendors and suppliers, 2) internal plant controls and systems, 3) telecommunications, including phone systems and cellular phones, 4) large customers, and 5) rail transportation. We consider vendors and suppliers a risk because of the lack of control we have over their operations. We are in the process of contacting by letter each vendor or supplier critical to our operations for information pertaining to their Year 2000 readiness. We consider our plant controls and systems a risk due to the complexity, variety, and extent of the embedded systems. We consider telecommunications a risk because it performs a critical function in a large number of our business processes and plant control functions. We consider large customers a risk because of the influence their electrical usage patterns have on our electrical generation and distribution systems. We consider rail transportation a risk because of our dependence for delivery of coal used at our coal-fired generating plants. The most reasonably likely worst case scenario we anticipate is the loss or partial interruption of local and long-distance telephone service, the interruption or significant delay to rail service effecting the coal deliveries to our generating plants, the unscheduled shut-down of the Wolf Creek nuclear operating plant, the potential loss of load from one or more large customers, and the loss of minimal generating capacity in the region for brief periods of time. Approximately 44% of our generating capacity utilizes coal as fuel and 22% of our generating capacity is attributed to Wolf Creek. We are addressing these risks in our contingency plans, and have or will be implementing a number of action plans in advance to mitigate these and other potential risks. Our contingency plans include pre-established actions to deal with potential operational impacts. For example, we have installed a company-wide trunked radio system which can be used in place of the commercial telecommunications systems, in the event those systems are interrupted. We plan to place in service, at reduced output, generating units which would 28 normally not be in service to help accommodate load shifts that would be caused by a large customer suddenly dropping or significantly reducing their electricity usage, or in the event of unexpected loss of some of our generation capacity or generation capacity of others in the region. In addition, we generally maintain more than a 30-day supply of coal at each of our coal-fired generating plants, reducing the effect of any temporary interruption of rail transportation and an unscheduled temporary shut-down of the Wolf Creek nuclear operating plant discussed below. While all business units and departments have developed contingency plans to cover essential business functions and anticipated possible Year 2000-related failure or interruption, these plans are continually reviewed and updated based on information learned as our Year 2000 readiness efforts proceed. WOLF CREEK NUCLEAR OPERATING CORPORATION (WCNOC): WCNOC has been evaluating and adjusting all known date-sensitive systems and equipment for Year 2000 compliance. WCNOC is developing a plan to effect the readiness of the plant for the coming of the Year 2000. This plan is designed to closely parallel the guidance provided by the Nuclear Energy Institute and the Nuclear Regulatory Commission (NRC). WCNOC is partnering with several industry groups to share information regarding evaluating items that are Year 2000 sensitive. As applications and devices are confirmed to be Year 2000 non-compliant, business decisions are being made to repair or retire the item. On May 11,1998 the NRC issued Generic Letter 98-01 entitled "Year 2000 Readiness of Computer Systems at Nuclear Power Plants." This letter expressed the NRC's expectations with regard to Year 2000 readiness. The letter also requires the licensee to file its Year 2000 plan and status report no later than July 1, 1999. WCNOC is developing contingency plans to address risk associated with Year 2000 Issues. These plans generally follow the guidance contained in NUCLEAR ENERGY INSTITUTE/NUCLEAR UTILITY SOFTWARE MANAGEMENT GROUP 98-07, NUCLEAR UTILITY READINESS CONTINGENCY PLANNING. The steps to be taken involve the determination of which items present a critical risk to the facility, review of the identified risks, determining mitigation strategies, and ensuring that each responsible organization develops appropriate contingency plans. In order to assess the licensees progress in preparing for Year 2000, the NRC scheduled audits at various nuclear power plant facilities during 1998 and early 1999. One of these audits was conducted at WCNOC during the month of November 1998. The findings of this audit were as follows: - The NEI/NUSMG 97-07 guidance is being followed. The Wolf Creek licensee has not identified any systems needed for safe shutdown as having Year 2000 problems. - Wolf Creek is making use of its existing quality assurance and modification programs and procedures to achieve Year 2000 readiness. Furthermore, Wolf Creek is engaged in extensive information sharing and interfaces with other entities on Year 2000 Issues. - The need for Year 2000 contingency planning is understood by the Wolf Creek licensee and in keeping with the NEI/NUSMG 98-07 recommendation, one individual has been designated as the single point of contact for contingency planning. 29 - Wolf Creek is at the detailed assessment phase except for the items of minimal significance designated as Limited Use Databases and spreadsheets, which come under the category of Limited Use Hardware/ Software. Year 2000 readiness for Wolf Creek is scheduled for September 15, 1999, and can be achieved based on the effort underway. - Executive management support was found to be aggressive at Wolf Creek. Management at Wolf Creek has dedicated the fiscal resources needed for successful completion of the year 2000 readiness program. Since Wolf Creek was designed during the 1970s and 1980s, most of the originally installed electronic plant equipment did not contain microprocessors. During this time frame, the NRC would not allow components required for safe shutdown of the plant to contain microprocessors. For these reasons, there is minimal Year 2000 risk associated with being able to safely shutdown the plant and maintain it in a safe shutdown condition. During the years since original construction, microprocessor based electronic components have been added in non-safe shutdown applications. Some of these (only two identified thus far and no others are anticipated) could shutdown the plant. Special attention will be paid to these devices to ensure that there is minimal Year 2000 risk associated with them. In the original design and through plant modifications, microprocessor based components were installed in plant monitoring applications such as the radiation monitoring equipment and the plant information computer. Similarly, in the area of non-plant operation computers and applications, WCNOC has several items which will require remediation. There is a possibility that these devices could cause a Year 2000 problem. Failure to adequately remediate any Year 2000 problems could require the plant's operations be limited or shutdown. WCNOC estimates that the most reasonably likely worse case scenario would be a temporary plant shutdown due to external electrical grid disturbances. While these disturbances may result in a temporary shutdown, the safety of the plant will not be compromised and the unit should restart shortly after the grid disturbance has been corrected. The table below sets forth estimates of the status of the components of WCNOC's Year 2000 readiness program at December 31, 1998.

30 WCNOC has established a goal of completing all assessments of affected systems by the end of the second quarter of 1999, with remediations being completed by the end of the third quarter. Remediations are being planned and initiated as the detailed assessment phase identifies the need, not at the end of the assessment period. The areas where the greatest potential for necessary remediations and/or more complex remediations could result were the first ones targeted for assessment so remediation planning could be started earlier. Many remediations will be completed before the end of the assessment period. In addition, WCNOC is communicating with others with which its systems interface or on which they rely with respect to those companies' Year 2000 compliance. Letters have been sent to all pertinent vendors to acquire this information. WCNOC has estimated the costs to complete the Year 2000 project at $4.6 million ($2.1 million, our share). As of December 31, 1998, $1.4 million ($0.6 million, our share) had been spent on the project. A summary of the projected costs to complete and actual costs incurred through December 31, 1998 is as follows: Projected Actual Costs Costs (Dollars in Thousands) Wolf Creek Labor and Expenses. . $ 494 $ 261 Contractor Costs . . . . . . . . 646 493 Remediation Costs. . . . . . . . 3,493 611 Total. . . . . . . . . . . . . $4,633 $1,365 Approximately $3.5 million ($1.6 million, our share) of WCNOC's total Year 2000 cost is associated with remediation. Of these remediation costs, $2.4 million ($1.1 million, our share) are associated with seven major jobs which are in the initial stages. All of these costs are being expensed as they are incurred and are being funded on a daily basis along with our normal costs of operations. In order to minimize the effects of delaying other information technology projects, WCNOC has and will continue to augment staffing during the identification and remediation phases of the project. This staffing, which will include both programmers and technical support personnel, will also be available during the testing and initial operating phases of the various systems. Market Risk Disclosure Market Price Risk: The company is exposed to market risk, including changes in commodity prices and interest rates. Commodity Price Exposure: The company uses derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of cash market prices. Given the amount of power purchased for during 1998, the company would have had exposure of approximately $3 million of operating income for a 10% increase in price per MW of electricity. Based upon mmbtu's of natural gas and fuel oil burned during 1998, the company had exposure of approximately $3 million of operating income for a 10% change in average price paid per mmbtu. Quantities of natural gas and electricity could vary dramatically year to year based on weather, unit outages and nuclear refueling. 31 Interest Rate Exposure: The company has approximately $46 million of variable rate debt as of December 31, 1998. A 100 basis point change in each debt series benchmark rate would impact net income on an annual basis by approximately $0.5 million. Western Resources Merger Agreement with Kansas City Power & Light Company On February 7, 1997, Western Resources signed a merger agreement with KCPL by which KCPL would be merged with and into Western Resources in exchange for Western Resources common stock. In December 1997, representatives of Western Resources' financial advisor indicated that they believed it was unlikely that they would be in a position to issue a fairness opinion required for the merger on the basis of the previously announced terms. On March 18, 1998, Western Resources and KCPL agreed to a restructuring of their February 7, 1997 merger agreement which will result in the formation of Westar Energy, a new electric company. Under the terms of the merger agreement, the electric utility operations of Western Resources will be transferred to the company, and KCPL and the company will be merged into NKC, Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive Western Resources common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of Western Resources common stock received may not exceed $30.00, and one share of Westar Energy common stock per KCPL share. The Western Resources Index Price is the 20 day average of the high and low sale prices for Western Resources common stock on the NYSE ending ten days prior to closing. If the Western Resources Index Price is less than or equal to $29.78 on the fifth day prior to the effective date of the combination, either party may terminate the agreement. Upon consummation of the combination, Western Resources will own approximately 80.1% of the outstanding equity of Westar Energy and KCPL shareholders will own approximately 19.9%. As part of the combination, Westar Energy will assume all of the electric utility related assets and liabilities of Western Resources, KCPL, and the company. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of Western Resources and the company, and $800 million from KCPL. Long-term debt of Western Resources, excluding Protection One (a subsidiary of Western Resources), and the company was $2.5 billion at December 31, 1998. Under the terms of the merger agreement, it is intended that Western Resources will be released from its obligations with respect to the company's debt to be assumed by Westar Energy. For additional information concerning the company's long-term debt and obligations under the La Cygne sale leaseback arrangements which will become obligations of Westar Energy, see Note 5 and Note 6 of Notes to Financial Statements. Consummation of the merger is subject to customary conditions. On July 30, 1998, the Western Resources' shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. Western Resources estimates the transaction to close in 1999, subject to receipt of all necessary approvals from regulatory and government agencies. 32 In testimony filed in February 1999, the KCC staff recommended the merger be approved but with conditions which Western Resources believes would make the merger uneconomical. The KCC is under no obligation to accept the KCC staff recommendation. In addition, legislation has been proposed in Kansas that could impact the transaction. Western Resources does not anticipate the proposed legislation to pass in its current form. Western Resources is not able to predict whether any of these initiatives will be adopted or their impact on the transaction, which could be material. On August 7, 1998, Western Resources and KCPL filed an amended application with the FERC to approve the Western Resources/KCPL merger and the formation of Westar Energy. Western Resources has received procedural schedule orders in Kansas and Missouri. These schedules indicate hearing dates beginning May 3, 1999 in Kansas and July 26, 1999 in Missouri. In February 1999, KCPL advised Western Resources that its Hawthorne generating station (479 MW coal facility) suffered material damage to its boiler which could prevent the unit's operation for an extended period. Western Resources is not able to ascertain at this time the impact of this matter on the merger. KCPL is a public utility company engaged in the generation, transmission, distribution, and sale of electricity to customers in western Missouri and eastern Kansas. We, KCPL and Western Resources have joint interests in certain electric generating assets, including Wolf Creek. For additional information see Note 11. Following the closing of the combination, Westar Energy is expected to have approximately one million electric utility customers in Kansas and Missouri, approximately $8.2 billion in assets and the ability to generate more than 8,800 megawatts of electricity. At December 31, 1998, Western Resources had deferred approximately $14 million related to the KCPL transaction. These costs will be included in the determination of the total consideration upon consummation of the transaction. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information relating to market risk disclosure is set forth in Other Information of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included herein. 33 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants 34 Financial Statements: Balance Sheets, December 31, 1998 and 1997 35 Statements of Income for the years ended December 31, 1998, 1997 and 1996 36 Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 37 Statements of Common Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 38 Notes to Financial Statements 39 SCHEDULES OMITTED The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in the financial statements and schedules presented: I, II, III, IV, and V. 34 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Kansas Gas and Electric Company: We have audited the accompanying balance sheets of Kansas Gas and Electric Company (a wholly-owned subsidiary of Western Resources, Inc.) as of December 31, 1998 and 1997, and the related statements of income, cash flows and common shareholders' equity for each of the three years in the period ended December 31, 1998. 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 generally accepted auditing standards. 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, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Kansas City, Missouri, January 27, 1999 35 KANSAS GAS AND ELECTRIC COMPANY BALANCE SHEETS (Dollars in Thousands)

36 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (Dollars in Thousands)

37 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (Dollars in Thousands)

38 KANSAS GAS AND ELECTRIC COMPANY STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands)

39 KANSAS GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Business: Kansas Gas and Electric Company (the company, KGE) is a rate-regulated electric utility and wholly-owned subsidiary of Western Resources, Inc. (Western Resources). The company is engaged principally in the production, purchase, transmission, distribution, and sale of electricity. The company serves approximately 283,000 electric customers in southeastern Kansas. At December 31, 1998, the company had no employees. All employees are provided by the company's parent, Western Resources, which allocates costs related to the employees of the company. The Company owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). The company records its proportionate share of all transactions of WCNOC as it does other jointly-owned facilities. The company prepares its financial statements in conformity with generally accepted accounting principles. The accounting and rates of the company are subject to requirements of the Kansas Corporation Commission (KCC) and the Federal Energy Regulatory Commission (FERC). The financial statements require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, to disclose contingent assets and liabilities at the balance sheet dates, and to report amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The company currently applies accounting standards for its rate regulated electric business that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", (SFAS 71) and, accordingly, has recorded regulatory assets and liabilities when required by a regulatory order or when it is probable, based on regulatory precedent, that future rates will allow for recovery of a regulatory asset. Cash and Cash Equivalents: The company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents. Property, Plant and Equipment: Property, plant and equipment is stated at cost that includes: contracted services, direct labor and materials, indirect charges for engineering, supervision, general and administrative costs, and an allowance for funds used during construction (AFUDC). The AFUDC rate was 6.00% for 1998, 5.86% for 1997, and 5.71% for 1996. The cost of additions and replacement units of property are capitalized. Maintenance costs and replacement of minor items of property are charged to expense as incurred. When units of depreciable property are retired, they are removed from the plant accounts and the original cost plus removal charges less salvage are charged to accumulated depreciation. Inventories and supplies are stated at average cost. 40 In accordance with regulatory decisions made by the KCC, the acquisition premium of approximately $801 million resulting from the KGE acquisition in 1992 is being amortized over 40 years. The acquisition premium is classified as property, plant and equipment on the Balance Sheets. Accumulated amortization as of December 31, 1998 and 1997 totaled $68.0 million and $47.9 million, respectively. Depreciation: Property, plant and equipment is depreciated on the straight-line method at rates approved by regulatory authorities. Property, plant and equipment is depreciated on an average annual composite basis using group rates that approximated 2.75% during 1998, 2.76% during 1997, and 2.81% during 1996. The company periodically evaluates its depreciation rates considering the past and expected future experience in the operation of its facilities. Fuel Costs: The cost of nuclear fuel in process of refinement, conversion, enrichment, and fabrication is recorded as an asset at original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor at December 31, 1998 and 1997, was $39.5 and $20.9 million, respectively. Regulatory Assets and Liabilities: Regulatory assets represent probable future sales associated with certain costs that will be recovered from customers through the ratemaking process. The company has recorded these regulatory assets in accordance with SFAS 71. If the company was required to terminate application of that statement for all of its regulated operations, the company would have to record the amounts of all regulatory assets and liabilities in its Statements of Income at that time. The company's earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets reflected in the financial statements at December 31, 1998 and 1997 are as follows: December 31, 1998 1997 (Dollars in Thousands) Recoverable taxes. . . . . . . . . . . . $175,759 $187,801 Debt issuance costs. . . . . . . . . . . 40,102 43,045 Deferred plant costs . . . . . . . . . . 30,657 30,979 Coal contract settlement costs . . . . . 8,392 10,035 Other regulatory assets. . . . . . . . . 5,879 6,708 Total regulatory assets . . . . . . . $260,789 $278,568 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: Disallowances related to the Wolf Creek nuclear generating facility. 41 Coal contract settlement costs: The company deferred costs associated with the termination of certain coal purchase contracts. These costs are being amortized through the year 2002. The company expects to recover all of the above regulatory assets in rates. A return is allowed on debt issuance costs, other than the refinancing of the La Cygne 2 lease, deferred plant costs and coal contract settlement costs. Sales: Sales are recognized as services are rendered and include estimated amounts for energy delivered but unbilled at the end of each year. Unbilled sales of $22.0 million and $21.5 million are recorded as a component of accounts receivable (net) on the Balance Sheets as of December 31, 1998 and 1997, respectively. The company's allowance for doubtful accounts receivable totaled $1.9 million and $1.7 million at December 31, 1998 and 1997, respectively. 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 which gave rise to the credits. Cash Surrender Value of Life Insurance: The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other assets on the Balance Sheets at December 31: 1998 1997 (Dollars in Millions) Cash surrender value of policies. . . . $486.3 $453.8 Borrowings against policies . . . . . . 476.9 442.2 COLI (net). . . . . . . . . . . . . . . $ 9.4 $ 11.6 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 $13.7 million in 1998, $0.6 in 1997 and $5.5 in 1996. New Pronouncements: In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). This statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting and is effective for fiscal years beginning after June 15, 42 1999. SFAS 133 cannot be applied retroactively. SFAS 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 and, at the company's election, before January 1, 1998. The company will adopt SFAS 133 no later than January 1, 2000. Management is presently evaluating the impact that adoption of SFAS 133 will have on the company's financial position and results of operations. Adoption of SFAS 133, however, could increase volatility in earnings. Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 2. COMMITMENTS AND CONTINGENCIES Manufactured Gas Sites: The company has been associated with three former manufactured gas sites which may contain coal tar and other potentially harmful materials. The company and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow the company to investigate these sites and set remediation priorities based upon the results of the investigations and risk analyses. At December 31, 1998, the costs incurred from preliminary site investigation and risk assessment have been minimal. Clean Air Act: The company must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. The company has installed continuous monitoring and reporting equipment to meet the acid rain requirements. The company does not expect material capital expenditures to be required to meet Phase II sulfur dioxide and nitrogen oxide requirements. Decommissioning: The company accrues 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. In February 1997, the KCC approved the 1996 Decommissioning Cost Study. Based on the study, the company's share of WCNOC's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $624 million during the period 2025 through 2033, or approximately $192 million in 1996 dollars. These costs were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1996 of 29 years. 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 $3.8 million in 1998 and will increase annually to $5.6 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.7%. The company's investment in the decommissioning fund, including reinvested earnings approximated $52.1 million and $43.5 million at December 31, 1998 and 1997, respectively. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. 43 The Financial Accounting Standards Board is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur: - The company's annual decommissioning expense could be higher than in 1998 - The estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation) - The increased costs could be recorded as additional investment in the Wolf Creek plant The company does not believe that such changes, if required, would adversely affect its operating results due to its current ability to recover decommissioning costs through rates. Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.7 billion for a single nuclear incident. If this liability limitation is insufficient, the U.S. Congress will consider taking whatever action is necessary to compensate the public for valid claims. The Wolf Creek owners (Owners) have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the Nuclear Regulatory Commission (NRC). Under this plan, the Owners are jointly and severally subject to a retrospective assessment of up to $88.1 million ($41.4 million, company's share) 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 on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million ($4.7 million, company's share) 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, company's 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 approved by the NRC. The company's share of any remaining proceeds can be used for property damages. If an accident at Wolf Creek exceeds $500 million in property damage and decontamination expenses and the decision is made to decommission the plant, the company's share of any remaining proceeds can be used to make up 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, the company may be subject to retrospective assessments under the current policies of approximately $7 million per year. Although the company maintains various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, the company's 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 the company's financial condition and results of operations. 44 Fuel Commitments: To supply a portion of the fuel requirements for its generating plants, the company has entered into various commitments to obtain nuclear fuel, coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1998, WCNOC's nuclear fuel commitments (company's share) were approximately $6.1 million for uranium concentrates expiring at various times through 2001, $24.9 million for enrichment expiring at various times through 2003 and $60.1 million for fabrication through 2025. At December 31, 1998, the company's coal contract commitments in 1998 dollars under the remaining terms of the contracts were approximately $598.3 million. The largest coal contract expires in 2020, with the remaining coal contracts expiring at various times through 2013. At December 31, 1998, the company's natural gas transportation commitment in 1998 dollars under the remaining terms of the contract were approximately $0.5 million. The natural gas transportation contract provides firm service to the company's Neosho gas burning facility through 2003. 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. The company's portion of the assessment for Wolf Creek is approximately $7 million, payable over 15 years. Management expects such costs to be recovered through the ratemaking process. 3. RATE MATTERS AND REGULATION KCC Rate Proceedings: In January 1997, the KCC approved an agreement that reduced electric rates for the company. Significant terms of the agreement are as follows: - The company made permanent an interim $8.7 million rate reduction implemented in May 1996. This reduction was effective February 1, 1997. - The company reduced annual rates by $36 million effective February 1, 1997. - The company rebated $2.3 million to its customers in January 1998. - The company reduced annual rates by an additional $10 million on June 1, 1998. - The company rebated an additional $2.3 million to its customers in January 1999. - The company will reduce annual rates by an additional $10 million on June 1, 1999. All rate decreases are cumulative. Rebates are one-time events and do not influence future rates. 45 4. SHORT-TERM BORROWINGS Information regarding the company's short-term borrowings, comprised of borrowings under the credit agreements and bank loans, is as follows: Year ended December 31, 1998 1997 (Dollars in Thousands) Borrowings outstanding at year end: Bank loans $ - $ 45,000 Weighted average interest rate on debt outstanding at year end (including fees) - % 6.44% Weighted average short-term debt outstanding during the year $ 616 $ 22,945 Weighted daily average interest rates during the year (including fees) 6.44% 6.46% 5. LONG-TERM DEBT The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and Deed of Trust (Mortgage) dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion. Amounts of additional bonds which 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. Debt discount and expenses are being amortized over the remaining lives of each issue. The improvement and maintenance fund requirements for certain first mortgage bond series can be met by bonding additional property. With the retirement of certain company pollution control series bonds, there are no longer any bond sinking fund requirements. During the years 1999 through 2003, $135 million of bonds will mature in 2003. No other bonds will mature during this time period. 46 Long-term debt outstanding is as follows at December 31: 1998 1997 (Dollars in Thousands) First mortgage bond series: 7.6% 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 . . . . . . . . . 13,673 13,757 Variable due 2027 (1). . . . . . 21,940 21,940 7.0% due 2031. . . . . . . . . . 327,500 327,500 Variable due 2032 (2). . . . . . 14,500 14,500 Variable due 2032 (3). . . . . . 10,000 10,000 387,613 387,697 Less: Unamortized discount . . . . . . 3,446 3,569 Long-term debt (net) . . . . . . . . $ 684,167 $ 684,128 Rates at December 31, 1998: (1) 3.50%, (2) 3.75%, (3) 3.75% 6. SALE-LEASEBACK OF LA CYGNE 2 In 1987, the company sold and leased back its 50% undivided interest in the La Cygne 2 generating unit. The La Cygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. The company remains responsible for its share of operation and maintenance costs and other related operating costs of La Cygne 2. The lease is an operating lease for financial reporting purposes. As permitted under the La Cygne 2 lease agreement, the company in 1992 requested the Trustee Lessor to refinance $341.1 million of secured facility bonds of the Trustee and owner of La Cygne 2. The transaction was requested to reduce recurring future net lease expense. In connection with the refinancing on September 29, 1992, a one-time payment of approximately $27 million was made by the company which has been deferred and is being amortized over the remaining life of the lease and included in operating expense as part of the future lease expense. At December 31, 1998, approximately $20.3 million of this deferral remained in regulatory assets on the Balance Sheet. Future minimum annual lease payments required under the La Cygne 2 lease agreement are approximately $34.6 million for each year through 2002, $39.4 million in 2003, and $537.2 million over the remainder of the lease. The gain realized at the date of the sale of La Cygne 2 has been deferred for financial reporting purposes, and is being amortized ($11.8 million per year) over the initial lease term in proportion to the related lease expense. The company's lease expense, net of amortization of the deferred gain and refinancing costs, was approximately $28.9 million for 1998, $27.3 million for 1997, and $22.5 million for 1996. 47 In addition the company has future minimum annual lease payments of approximately $965,000 for each year through 2003 and $2.9 million over the remainder of the lease. 7. INCOME TAXES Income tax expense is composed of the following components at December 31: 1998 1997 1996 (Dollars in Thousands) Currently payable: Federal. . . . . . . . . $ 53,297 $ 34,641 $ 31,135 State. . . . . . . . . . 12,080 7,982 11,948 Deferred: Federal. . . . . . . . . (14,299) (18,503) (218) State. . . . . . . . . . (2,866) (3,467) (3,358) Amortization of investment tax credits . . . . . . (3,241) (3,245) (3,249) Total income tax expense . $ 44,971 $ 17,408 $ 36,258 Under SFAS 109, temporary differences gave rise to deferred tax assets and deferred tax liabilities as follows at December 31: 1998 1997 (Dollars in Thousands) Deferred tax assets: Deferred gain on sale-leaseback. . . . . $ 92,427 $ 97,634 Other. . . . . . . . . . . . . . . . . . 42,806 43,330 Total deferred tax assets. . . . . . . 135,233 140,964 Deferred tax liabilities: Accelerated depreciation and other . . . 376,113 386,382 Acquisition premium. . . . . . . . . . . 290,576 298,582 Deferred future income taxes . . . . . . 175,759 187,801 Other. . . . . . . . . . . . . . . . . . 14,667 22,561 Total deferred tax liabilities . . . . 857,115 895,326 Investment tax credits . . . . . . . . . . 63,234 66,476 Accumulated deferred income taxes, net . . $ 785,116 $ 820,838 In accordance with various rate orders, the company has 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. 48 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: Year Ended December 31, 1998 1997 1996 (Dollars in Thousands) Effective Income Tax Rate 30% 25% 27% Effect of: State income taxes (4) (4) (4) Amortization of investment tax credits 2 5 2 Corporate-owned life insurance policies 9 12 7 Accelerated depreciation flow through and amortization, net (2) (4) 2 Other - 1 1 Statutory Federal Income Tax Rate 35% 35% 35% 8. LEGAL PROCEEDINGS The company is involved in various legal, environmental and regulatory proceedings. Management believes that adequate provision has been made and accordingly believes that the ultimate dispositions of these matters will not have a material adverse effect upon the company's overall financial position or results of operations. 9. FAIR VALUE OF 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 Statement of Financial Accounting Standards No. 107 "Disclosures about Fair Value of Financial Instruments". Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost which approximates fair value. The decommissioning trust is recorded at fair value and is based on the quoted market prices at December 31, 1998 and 1997. The fair value of fixed-rate debt 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 amount of accounts receivable and other current financial instruments approximate fair value. The fair value estimates presented herein are based on information available at December 31, 1998 and 1997. These fair value estimates have not been comprehensively revalued for the purpose of these financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein. Because the company's operations are regulated, the company believes that any gains or losses related to the retirement of debt would not have a material effect on the company's financial position or results of operations. 49 The carrying values and estimated fair values of the company's financial instruments are as follows: Carrying Value Fair Value December 31, 1998 1997 1998 1997 (Dollars in Thousands) Decommissioning trust. . . $ 52,093 $ 43,514 $ 52,093 $ 43,514 Fixed-rate debt. . . . . . 641,172 641,257 684,125 660,266 10. PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at December 31: 1998 1997 (Dollars in Thousands) Electric plant in service. . . . . . $3,580,433 $3,545,942 Less - Accumulated depreciation. . . 1,125,735 1,051,107 2,454,698 2,494,835 Construction work in progress. . . . 32,943 29,432 Nuclear fuel (net) . . . . . . . . . 39,497 40,696 Net Utility Plant. . . . . . . . . 2,527,138 2,564,963 Non-utility plant in service . . . . 219 212 Net Property, Plant and Equipment. $2,527,357 $2,565,175 The carrying value of long-lived assets, including intangibles are reviewed for impairment whenever events or changes in circumstances indicate they may not be recoverable. 11. JOINT OWNERSHIP OF UTILITY PLANTS Company's Ownership at December 31, 1998 In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 162,756 $ 109,336 343 50 Jeffrey 1 (b) Jul 1978 71,831 31,883 147 20 Jeffrey 2 (b) May 1980 68,477 31,734 147 20 Jeffrey 3 (b) May 1983 99,964 41,061 144 20 Wolf Creek (c) Sep 1985 1,377,348 429,934 547 47 (a) Jointly owned with Kansas City Power & Light Company (KCPL) (which owns 50%) (b) Jointly owned with Western Resources (which owns 64%) and UtiliCorp United Inc. (which owns 16%) (c) Jointly owned with KCPL (which owns 47%) and Kansas Electric Power Cooperative, Inc. (which owns 6%) 50 Amounts and capacity represent the company's share. The company's share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in La Cygne 2 (representing 334 MW capacity) sold and leased back to the company in 1987, are included in operating expenses on the Statements of Income. The company's share of other transactions associated with the plants is included in the appropriate classification in the company's financial statements. 12. RELATED PARTY TRANSACTIONS The cash management function, including cash receipts and disbursements, for the company is performed by Western Resources. An intercompany account is used to record net receipts and disbursements handled by Western Resources. The net amount advanced by the company to Western Resources approximated $64 million and $73 million at December 31, 1998 and 1997, respectively. These amounts are recorded as advances to parent company in current assets on the Balance Sheets. Certain operating expenses have been allocated to the company 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 allocators. Management believes such allocation procedures are reasonable. During 1998, the company declared dividends to Western Resources of $100 million. 13. WESTERN RESOURCES AND KANSAS CITY POWER & LIGHT COMPANY MERGER AGREEMENT On February 7, 1997, Kansas City Power & Light Company (KCPL) and Western Resources entered into an agreement whereby KCPL would be combined with Western Resources. In December 1997, representatives of Western Resources' financial advisor indicated that they believed it was unlikely that they would be in a position to issue a fairness opinion required for the merger on the basis of the previously announced terms. On March 18, 1998, Western Resources and KCPL agreed to a restructuring of their February 7, 1997 merger agreement which will result in the formation of Westar Energy, a new electric company. Under the terms of the merger agreement, the electric utility operations of Western Resources will be transferred to the company, and KCPL and the company will be merged into NKC, Inc., a subsidiary of Western Resources. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive Western Resources common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of Western Resources common stock received may not exceed $30.00, and one share of Westar Energy common stock per KCPL share. The Western Resources Index Price is the 20 day average of the high and low sale prices for Western Resources common stock on the NYSE ending ten days prior to closing. If the Western Resources Index Price is less than or equal to $29.78 on the fifth day prior to the effective date of the combination, either party may terminate the agreement. Upon consummation of the combination, Western Resources will own 51 approximately 80.1% of the outstanding equity of Westar Energy and KCPL shareholders will own approximately 19.9%. As part of the combination, Westar Energy will assume all of the electric utility related assets and liabilities of Western Resources, KCPL, and the company. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of Western Resources and the company, and $800 million from KCPL. Long-term debt of Western Resources, excluding Protection One (a subsidiary of Western Resources), and the company was $2.5 billion at December 31, 1998, and $2.1 billion at December 31, 1997. Under the terms of the merger agreement, it is intended that Western Resources will be released from its obligations with respect to the company's debt to be assumed by Westar Energy. Consummation of the merger is subject to customary conditions. On July 30, 1998, the Western Resources' shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. Western Resources estimates the transaction to close in 1999, subject to receipt of all necessary approvals from regulatory and government agencies. In testimony filed in February 1999, the KCC staff recommended the merger be approved but with conditions which Western Resources believes would make the merger uneconomical. The KCC is under no obligation to accept the KCC staff recommendation. In addition, legislation has been proposed in Kansas that could impact the transaction. Western Resources does not anticipate the proposed legislation to pass in its current form. Western Resources is not able to predict whether any of these initiatives will be adopted or their impact on the transaction, which could be material. On August 7, 1998, Western Resources and KCPL filed an amended application with the FERC to approve the Western Resources/KCPL merger and the formation of Westar Energy. Western Resources has received procedural schedule orders in Kansas and Missouri. These schedules indicate hearing dates beginning May 3, 1999 in Kansas and July 26, 1999 in Missouri. In February 1999, KCPL advised Western Resources that its Hawthorne generating station (479 MW coal facility) suffered material damage to its boiler which could prevent the unit's operation for an extended period. Western Resources is not able to ascertain at this time the impact of this matter on the merger. KCPL is a public utility company engaged in the generation, transmission, distribution, and sale of electricity to customers in western Missouri and eastern Kansas. The company, KCPL and Western Resources have joint interests in certain electric generating assets, including Wolf Creek. At December 31, 1998, Western Resources had deferred approximately $14 million related to the KCPL transaction. These costs will be included in the determination of total consideration upon consummation of the transaction. For additional information on the Merger Agreement with KCPL, see Western Resources' Registration Statement on Form S-4 filed on June 9, 1998. 52 14. SEGMENTS OF BUSINESS In 1998, the company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires the company to define and report the company's business segments based on how management currently evaluates its business. The company is evaluated from a segment perspective as a part of its parent company, Western Resources. The company is an integral component of Western Resources and its financial position and operations are managed as such. Based on the management approach to determining business segments, the company only has one business segment. This segment is nuclear generation. The company's remaining operations of fossil generation and energy delivery are fully integrated with those of Western Resources. Electric operations and nuclear generation comprise the company's regulated electric utility business in Kansas. Electric operations involve the production, transmission and distribution of electric power for sale to approximately 283,000 retail and wholesale customers in Kansas. Nuclear generation represents the company's 47% ownership in the Wolf Creek nuclear generating facility. This segment does not have any external sales. The accounting policies of the segments are substantially the same as those described in the summary of significant accounting policies. The company evaluates segment performance based on earnings before interest and taxes. The company has no single external customer from which it receives ten percent or more of revenues. Year Ended December 31, 1998: Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales. . . $ 648,379 $ - $ - $ 648,379 Allocated sales . . 117,517 117,517 (235,034) - Depreciation and amortization . . . 59,239 39,583 - 98,822 Earnings before interest and taxes 219,014 (20,920) - 198,094 Interest expense. . 49,358 Earnings before income taxes . . . 148,736 Identifiable assets 1,936,462 1,121,509 3,057,971 53 Year Ended December 31, 1997: Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales. . . $ 614,445 $ - $ - $ 614,445 Allocated sales . . 102,330 102,330 (204,660) - Depreciation and amortization . . . 57,521 65,902 - 123,423 Earnings before interest and taxes 180,954 (60,968) - 119,986 Interest expense. . 50,450 Earnings before income taxes . . . 69,536 Identifiable assets 1,962,856 1,154,522 3,117,108 Year Ended December 31, 1996: Electric Nuclear Eliminating Operations Generation Items Total (Dollars in Thousands) External sales. . . $ 654,570 $ - $ - $ 654,570 Allocated sales . . 100,592 100,592 (201,184) - Depreciation and amortization . . . 56,611 57,242 - 113,853 Earnings before interest and taxes 242,179 (51,585) 190,594 Interest expense. . 58,062 58,062 Earnings before income taxes . . . 132,532 Identifiable assets 2,128,552 1,190,335 3,318,887 54 15. QUARTERLY FINANCIAL STATISTICS (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. The business of the company is seasonal in nature and, in the opinion of management, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. 1998 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (Dollars in Thousands) Sales . . . . . . . . . . . $134,566 $162,816 $216,034 $134,963 Income from Operations. . . 36,033 44,112 81,063 28,210 Net income. . . . . . . . . 22,415 28,507 43,329 9,514 1997 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (Dollars in Thousands) Sales . . . . . . . . . . . $143,791 $148,826 $191,066 $130,762 Income from Operations. . . 30,364 32,421 66,724 (5,501) Net income. . . . . . . . . 11,172 15,492 31,775 (6,311) ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There were no disagreements with accountants on accounting and financial disclosure. 55 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Western Resources, Inc. owns 100% of the Company's outstanding common stock. A Director Business Experience Since 1994 and Other Continuously Name Age Directorships Other Than The Company Since Annette M. 36 Chairman of the Board (since Jan. 1999) 1999 Beck and President (since Oct. 1998), Kansas Gas and Electric Company; Vice President, Customer Service (since Oct. 1998); Director Customer Operations (Aug. 1997 to Oct. 1998); and prior to that Director Strategic Planning, Western Resources, Inc. Anderson E. 65 President, Jackson Mortuary, 1994 Jackson Wichita, Kansas Directorships The National Business League Donald A. 65 Consultant, Investment Management Group, 1992 Johnston Commerce Bank, Lawrence, Kansas, (1)(2) (since July 1996); Retired President and Chairman (Emeritus), Maupintour, Inc, Lawrence, Kansas Directorships Commerce Bank, Lawrence, Kansas James A. 41 Vice President, Investor Relations and 1997 Martin Strategic Planning (since Oct. 1998); Vice President, Finance (July 1995 to Oct. 1998); and prior to that Executive Director Regulatory and Rates Western Resources, Inc. Marilyn B. 49 President Kansas, NationsBank N.A. 1994 Pauly Wichita, Kansas (1) Directorships Farmers Mutual Alliance Insurance Company Richard D. 66 President, Range Oil Company 1993 Smith Directorships NationsBank N.A. HCA Wesley Medical Center, Wichita, Kansas (1) Member of the Audit Committee of which Mr. Johnston is Chairman. The Audit Committee has responsibility for the investigation and review of the financial affairs of the Company and its relations with independent accountants. 56 (2) Mr. Johnston was a director of the former Kansas Gas and Electric Company since 1980. Outside Directors are paid $3,750 per quarter retainer and are paid an attendance fee of $600 for Directors' meetings ($300 if attending by phone). A committee attendance fee of $800 is paid to the outside Director Audit Committee Chairman, and $500 to other outside Committee members. All outside Directors are reimbursed mileage and expenses while attending Directors' and Committee Meetings. During 1998, the Board of Directors met five times and the Audit Committee met once. Each director attended at least 75% of the total number of Board and Committee meetings held while he/she served as a director or a member of the committee. Other information required by Item 10 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Information required by Item 11 is omitted pursuant to General Instruction J(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 J(2)(c) to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by Item 13 is omitted pursuant to General Instruction J(2)(c) to Form 10-K. 57 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K The following financial statements are included herein under Item 8. FINANCIAL STATEMENTS Balance Sheets, December 31, 1998 and 1997 Statements of Income for the years ended December 31, 1998, 1997 and 1996 Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 Statements of Common Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 Notes to Financial Statements REPORTS ON FORM 8-K None 58 EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. Description 2(a) Amended and Restated Agreement and Plan of Merger dated March 18, 1998 (Filed electronically) 3(a) Articles of Incorporation (Filed as Exhibit 3(a) to Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 3(b) Certificate of Merger of Kansas Gas and Electric Company into I KCA 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) Form 10-K I for the year ended December 31, 1992, File No. 1-7324) 4(c) Mortgage and Deed of Trust, dated as of April 1, 1940 to I Guaranty 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 thirty-eight 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 and March 1, 1994, (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 59 Description 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) La Cygne 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 La Cygne 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 Computation of Ratio of Consolidated Earnings to Fixed Charges (Filed electronically) 23 Consent of Independent Public Accountants, Arthur Andersen LLP (Filed electronically) 27 Financial Data Schedule (Filed electronically) 60 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 March 31, 1999 By /s/ Annette M. Beck Annette M. Beck, Chairman of the Board and President 61 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/ ANNETTE M. BECK Chairman of the Board and (Annette M. Beck) President (Principal Executive March 31, 1999 Officer) /s/ RICHARD D. TERRILL Secretary, Treasurer and General (Richard D. Terrill) Counsel (Principal Financial March 31, 1999 and Accounting Officer) /s/ ANDERSON E. JACKSON (Anderson E. Jackson) /s/ DONALD A. JOHNSTON (Donald A. Johnston) /s/ JAMES A. MARTIN Directors March 31, 1999 (James A. Martin) /s/ MARILYN B. PAULY (Marilyn B. Pauly) /s/ RICHARD D. SMITH (Richard D. Smith)

Exhibit 12 KANSAS GAS AND ELECTRIC COMPANY Computations of Ratio of Earnings to Fixed Charges (Dollars in Thousands)

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 Statements File No. 33-50075 of Kansas Gas and Electric Company on Form S-3. ARTHUR ANDERSEN LLP Kansas City, Missouri, January 27, 1999

5 This schedule contains summary financial information extracted from the Balance Sheet at December 31, 1998 and the Statement of Income for the year ended December 31, 1998 and is qualified in its entirety by reference to such financial statements. 1,000 YEAR DEC-31-1998 DEC-31-1998 41 0 68,416 1,903 43,121 189,177 3,653,092 1,125,735 3,057,971 148,328 684,167 0 0 1,065,634 72,610 3,057,971 648,379 648,379 149,360 458,961 0 0 49,358 148,736 44,971 103,765 0 0 0 103,765 0 0