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 1-3523 WESTERN RESOURCES, INC. (Exact name of registrant as specified in its charter) KANSAS 48-0290150 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 818 KANSAS AVENUE, TOPEKA, KANSAS 66612 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code 785/575-6300 Securities registered pursuant to Section 12(b) of the Act: Common Stock, $5.00 par value New York Stock Exchange (Title of each class) (Name of each exchange on which registered) Securities registered pursuant to Section 12(g) of the Act: Preferred Stock, 4 1/2% Series, $100 par value (Title of Class) 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 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) State the aggregate market value of the voting stock held by nonaffiliates of the registrant. Approximately $1,728,898,185 of Common Stock and $14,673,374 of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there is no readily ascertainable market value) at April 8, 1999. Indicate the number of shares outstanding of each of the registrant's classes of common stock. Common Stock, $5.00 par value 66,336,621 (Class) (Outstanding at April 14, 1999) Documents Incorporated by Reference: Part Document III Items 10-13 of the Company's Definitive Proxy Statement for the Annual Meeting of Shareholders to be held June 3O, 1999. WESTERN RESOURCES, INC. FORM 10-K December 31, 1998 TABLE OF CONTENTS Description Page PART I Item 1. Business 3 Item 2. Properties 26 Item 3. Legal Proceedings 29 Item 4. Submission of Matters to a Vote of Security Holders 30 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 30 Item 6. Selected Financial Data 31 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 32 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 59 Item 8. Financial Statements and Supplementary Data 60 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 103 PART III Item 10. Directors and Executive Officers of the Registrant 103 Item 11. Executive Compensation 103 Item 12. Security Ownership of Certain Beneficial Owners and Management 103 Item 13. Certain Relationships and Related Transactions 103 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 104 Signatures 111 PART I ITEM 1. BUSINESS GENERAL Western Resources, Inc. is a publicly traded consumer services company, incorporated in 1924. Our primary business activities are providing electric generation, transmission and distribution services to approximately 620,000 customers in Kansas and providing monitored services to approximately 1.5 million customers in North America, the United Kingdom and Continental Europe. In addition, through our 45% ownership interest in ONEOK, Inc. (ONEOK), natural gas transmission and distribution services are provided to approximately 1.4 million customers in Oklahoma and Kansas. Rate regulated electric service is provided by KPL, a division of the company, and Kansas Gas and Electric Company (KGE), a wholly-owned subsidiary. Monitored services are provided by Protection One, Inc. (Protection One), a publicly-traded, approximately 85%-owned subsidiary. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Our corporate headquarters are located at 818 Kansas Avenue, Topeka, Kansas 66612. As of December 31, 1998, we had 6,960 employees. We did not experience any strikes or work stoppages during 1998. Our current contract with the International Brotherhood of Electrical Workers extends through June 30, 1999. The contract covers approximately 1,440 employees. Protection One has approximately 800 employees in France who are covered by a collective bargaining agreement. On February 7, 1997, we signed a merger agreement with Kansas City Power & Light Company (KCPL) by which KCPL would be merged with and into the company in exchange for company stock. In December 1997, representatives of our 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, we and KCPL agreed to a restructuring of our 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, our electric utility operations will be transferred to KGE, and KCPL and KGE will be merged into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive company common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of company 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 company common stock on the New York Stock Exchange 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, we 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 KGE. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of Western Resources and KGE, and $800 million of debt of KCPL. Long-term debt of the company, excluding Protection One, was $2.5 billion at December 31, 1998. Under the terms of the merger agreement, it is intended that we will be released from our obligations with respect to our debt to be assumed by Westar Energy. Pursuant to the merger agreement, we have agreed, among other things, to call for redemption all outstanding shares of our 4 1/2% Series Preferred Stock, par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per share, and 5% Series Preferred Stock, par value $100 per share. Consummation of the merger is subject to customary conditions. On July 30, 1998, our shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. We estimate 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 we believe would make the merger uneconomical. The merger agreement allows us to terminate the agreement if regulatory approvals are not acceptable. 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. We do not anticipate the proposed legislation to pass in its current form. We are 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, we 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. We have 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. We, KCPL and KGE have joint interests in certain electric generating assets, including Wolf Creek. For additional information, see Item 2. Properties, Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 21 of Notes to Consolidated Financial Statements. In November 1997, we completed a strategic alliance with ONEOK and contributed substantially all of our natural gas business to ONEOK in exchange for a 45% ownership interest in ONEOK. Our ownership interest is comprised of approximately 3.2 million common shares and approximately 20.1 million convertible preferred shares. If all the preferred shares were converted, we would own approximately 45% of ONEOK's common shares presently outstanding. Following the strategic alliance, the consolidated energy sales, related cost of sales and operating expenses in 1997 for our natural gas business have been replaced by investment earnings in ONEOK. Protection One had a year of rapid expansion and continued growth. During the year, Protection One doubled the size of its customer base from about 750,000 customers to about 1.5 million customers. This growth was achieved through acquisitions and Protection One's Dealer Program. During 1998, Protection One invested approximately $549 million in security company acquisitions. Highlights of this activity include: - Network Multi-Family - A leading provider of monitored services to multi-family dwellings. This acquisition added approximately 200,000 customers. - Multimedia Security Services - A purchase of assets including a large security monitoring center in Wichita, Kansas, that added about 147,000 customers. - Compagnie Europeenne de Telesecurite - An acquisition of a French monitored services provider which added 60,000 customers and established a major presence in Western Europe. In October 1998, Protection One announced an agreement to acquire Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal emergency response and support services in North America. Based on the average closing price for the three trading days prior to April 8, 1999, the value of the consideration to be paid under the merger agreement is approximately $129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has advised Protection One that it is evaluating the restatement of Protection One's financial statements. The consideration to be given in the Lifeline transaction is by design variable and is subject to change within certain parameters until the closing date. Interested parties should obtain the most recent proxy/registration statement for further analysis of the transaction. SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 19 of the Notes to Consolidated Financial Statements included herein. ELECTRIC UTILITY OPERATIONS General We supply electric energy at retail to approximately 620,000 customers in 471 communities in Kansas. These include Wichita, Topeka, Lawrence, Manhattan, Salina, and Hutchinson. We also supply electric energy at wholesale to the electric distribution systems of 64 communities and 4 rural electric cooperatives. We have contracts for the sale, purchase or exchange of electricity with other utilities. We also receive a limited amount of electricity through parallel generation. Our electric energy deliveries for the last three years are as follows: 1998 1997 1996 (Thousands of MWH) Residential. . . . 5,815 5,310 5,265 Commercial . . . . 6,199 5,803 5,667 Industrial . . . . 5,808 5,714 5,622 Wholesale and Interchange. . . 4,826 5,334 5,908 Other. . . . . . . 108 107 105 Total. . . . . . 22,756 22,268 22,567 Our electric sales for the last three years are as follows: 1998 1997 1996 (Dollars in Thousands) Residential. . . . $ 428,680 $ 392,751 $ 403,588 Commercial . . . . 356,610 339,167 351,806 Power Marketing. . 382,601 69,827 - Industrial . . . . 257,186 254,076 262,989 Wholesale and Interchange. . . 145,320 142,506 143,380 Other. . . . . . . 41,288 31,721 35,652 Total. . . . . . $1,611,685 $1,230,048 $1,197,415 Competition: 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 KGE merger, we agreed to open access of our transmission system for wholesale transactions. In 1996, the 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 separate their generation market functions away from their transmission operations. As required by this order, we have completed this separation. For further discussion regarding competition and the potential impact on the company, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 our Jeffrey Energy Center (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. There is sufficient low sulfur coal under contract (See Coal) to allow compliance with such limits at Lawrence, Tecumseh and La Cygne 1 for the life of the contracts. All 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 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 10 of the Notes to Consolidated Financial Statements included herein. Regulation and rates: As a Kansas electric utility, we are subject to the jurisdiction of the KCC which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. We are subject to the jurisdiction of the FERC and KCC with respect to the issuance of securities. 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. That request could be denied in whole or in part. Any increase in fuel costs from the projected average which we 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. We are exempt as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 from all provisions of that Act, except Section 9(a)(2). Additionally, we are subject to the jurisdiction of the FERC, including our sales of electricity for resale. KGE is also subject to the jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations and safety. Additional information with respect to Rate Matters and Regulation as set forth in Note 5 of Notes to Consolidated Financial Statements is included herein. Fossil Generation Capacity: The aggregate net generating capacity of our system is presently 5,356 megawatts (MW). The system has interests in 22 fossil fueled steam generating units, one nuclear generating unit (47% interest), seven combustion peaking turbines and two diesel generators located at eleven generating stations. Two units of the 22 fossil fueled units (aggregating 100 MW of capacity) have been "mothballed" for future use (See Item 2. Properties). Our 1998 peak system net load occurred August 20, 1998, and amounted to 4,201 MW. Our net generating capacity together with power available from firm interchange and purchase contracts, provided a capacity margin of approximately 14% above system peak responsibility at the time of the peak. We received a prepayment in 1994 of approximately $41 million for capacity (42 MW) and transmission charges through the year 2013 in an agreement with Oklahoma Municipal Power Authority. KGE has an agreement with Midwest Energy, Inc. (MWE) to provide MWE with peaking capacity of 61 MW through the year 2008. KGE 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. We have another agreement with Empire to provide Empire with peaking and base load capacity (10 MW in 1995 increasing to 162 MW in 2000) through the year 2010. Future Capacity: In order to meet the needs of our electric utility customers, we plan to install three new combustion turbine generators for use as peaking units. The installed capacity of the three new generators will approximate 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. We estimate that the project will require $120 million in capital resources through the completion of the projects in 2001. In addition, we plan to return an inactive generation plant in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7 million. On January 4, 1999, we and Empire signed a memorandum of understanding that provides for the joint ownership of a 500-megawatt combined cycle generating unit, which Empire will operate. We estimate that the project will require $90 million in capital resources and that we will own 40% of the generating unit. Construction of the unit is expected to begin in the fall of 1999 with operation beginning approximately 20 months later. 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 3,347 MW of the total 5,356 MW of generating capacity and our nuclear unit provides 547 MW of capacity. Of the remaining 1,462 MW of generating capacity, units that can burn either natural gas or oil account for 1,378 MW, and the remaining units which burn only diesel fuel account for 84 MW (See Item 2. Properties). During 1998, low sulfur coal was used to produce 73% of our electricity. Nuclear produced 20% 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 77% of our electricity and nuclear will be used to produce approximately 15%. 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 JEC have an aggregate capacity of 1,860 MW (our 84% share) (See Item 2. Properties). We 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 $1.04 per MMBtu or $18.82 per ton during 1998. Coal is transported from Wyoming under a long-term rail transportation contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP) railroads to JEC through December 31, 2013. Rates are based on net load carrying capabilities of each rail car. We provide 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 summarized 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. The blended fuel mix contains approximately 85% Powder River Basin coal. 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 BNSF 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. The coal-fired units located at the Tecumseh and Lawrence Energy Centers have an aggregate generating capacity of 810 MW (See Item 2. Properties). The company sourced low sulfur coal from Colorado through December 31, 1998 and began sourcing coal from Montana under contracts through December 31, 2000. The Colorado coal was transported by the UP and BNSF railroads under contracts expiring December 31, 1998. The Colorado coal supplied in 1998 had an average Btu content of approximately 11,292 Btu per pound and an average sulfur content of .77 lbs/MMBtu (See Environmental Matters). During 1998, the average delivered cost of Colorado coal for the Lawrence units was approximately $1.22 per MMBtu or $26.51 per ton and the average delivered cost of Colorado coal for the Tecumseh units was approximately $1.27 per MMBtu or $27.79 per ton. Montana coal is transported by BNSF railroad under a contract expiring December 31, 2000. The Montana coal supplied in 1998 had an average Btu content of approximately 9,362 Btu per pound and an average sulfur content of .36 lbs./MMBtu (See Environmental Matters). During 1998, the average delivered cost of Montana coal for the Lawrence units was approximately $0.92 per MMBtu or $17.52 per ton and the average delivered cost of Montana coal for the Tecumseh units was approximately $0.94 per MMBtu or $17.55 per ton. We have entered into all of our coal contracts in 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 are 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 in 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. See also Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Natural Gas: We use natural gas as a primary fuel in our Gordon Evans, Murray Gill, Neosho, Abilene, and Hutchinson Energy Centers and in the gas turbine units at our Tecumseh generating station. Natural gas is also used as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. Natural gas for all facilities is supplied by readily available gas from the short-term economical spot market and will supply the system with the flexible natural gas supply to meet operational needs. For Gordon Evans, Murray Gill and Neosho Energy Centers, we maintain firm natural gas transportation capacity through Williams Gas Pipelines Central through April 1, 2010. For Abilene and Hutchinson Energy Centers, we maintain interruptible natural gas transportation with Kansas Gas Service through March 31, 2001. 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 the JEC and La Cygne generating stations. All oil burned during the past several years has been obtained by spot market purchases. At December 31, 1998, we had approximately 3 million gallons of No. 2 oil and 23 million gallons of No. 6 oil which we believe 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. 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 used by the company. KPL Plants 1998 1997 1996 Per Million Btu: Coal. . . . . . . . . . $1.15 $1.17 $1.14 Gas . . . . . . . . . . 2.29 2.88 2.50 Oil . . . . . . . . . . 4.40 3.72 4.01 Cents per KWH Generation . 1.31 1.32 1.30 KGE Plants 1998 1997 1996 Per Million Btu: Nuclear . . . . . . . . $0.48 $0.51 $0.50 Coal. . . . . . . . . . 0.86 0.89 0.88 Gas . . . . . . . . . . 2.28 2.56 2.30 Oil . . . . . . . . . . 4.05 3.32 2.74 Cents per KWH Generation . 0.94 1.00 0.93 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. Wolf Creek has active contracts to acquire uranium from 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. Wolf Creek has active contracts for uranium enrichment with Urenco and USEC. Contracted arrangements cover 88% of Wolf Creek's uranium enrichment requirements for operation of Wolf Creek through March 2005. The balance is expected to be obtained through spot market and term contract purchases. Wolf Creek has entered into all of its uranium, uranium hexaflouride and uranium enrichment arrangements in the ordinary course of business and is not substantially dependent upon these agreements. Wolf Creek believes there are other suppliers available at reasonable prices to replace, if necessary, these contracts. In the event that Wolf Creek were required to replace these contracts, Wolf Creek would not anticipate a substantial disruption of its 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 (NWPA) of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one- tenth of a cent for each kilowatt-hour of net nuclear generation delivered and sold for future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales and currently recovered through rates. In 1996, a U.S. Court of Appeals issued a decision that the NWPA 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, KGE 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, Wolf Creek 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 its 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. Wolf Creek 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 has started plans 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. Attempts have been made 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 was taken off-line on April 3, 1999, for its tenth refueling and maintenance outage. The outage is expected to last approximately 35 days during which time electric demand will be met primarily by the company's 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 10 of the Notes to Consolidated Financial Statements. Power Delivery The Power Delivery segment transports electricity from the generating stations to approximately 620,000 customers. Power Delivery's assets include substations, poles, wire, underground cable systems, and customer meters. Power Delivery's objective is to provide low-cost electricity while maintaining a high level of system reliability and customer service. Power Delivery transports wholesale energy through its interconnections with the company's neighboring utilities. We maintain interconnection relationships through the following agreements. 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 10 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. The Power Delivery segment includes the customer service portion of our electric utility business. Customer service includes our phone center for business and mass market accounts, our credit and collections function, billing, meter reading, our meter shop, field service work, revenue accounting, walk-in offices, day-to-day operational interface with the KCC staff, and theft, diversion, and claims. 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. MONITORED SERVICES General: In addition to life safety and property monitoring services, Protection One provides its customers with enhanced services that include: - Extended service protection - Patrol and alarm response - Two-way voice communication - Pager service - Cellular back-up - Mobile security services Approximately 85% of Protection One's sales are contractually recurring for monitoring alarm security systems and other related services. Protection One's principal activity is immediately responding to the security and safety needs of its customers 24 hours a day. Protection One's sales are generated primarily from recurring monthly payments for monitoring and maintaining the alarm systems that are installed in its customers' premises. Security systems are designed to detect burglaries, fires and other events. Through a network of 66 service branches and four satellite offices in North America and 49 service branches in continental Europe and the United Kingdom, Protection One provides maintenance service of security systems and, in certain markets, armed response to verify that an actual emergency has occurred. Protection One provides its services to residential (both single family and multifamily residences), commercial and wholesale customers of the alarm monitoring industry. Although Protection One intends to grow its presence in each of the customers classes, it believes that the residential customer class, which represents in excess of 80% of its customer base, is the most attractive class of the alarm business because of its lower penetration and stronger growth prospects, higher gross margins and larger potential size. At December 31, 1998, Protection One's customer base composition was as follows: Percentage of Customer Class Total Single Family 57% Multifamily/Apartment 21% Commercial 12% Wholesale 10% Total 100% Wholesale customers represent those customers that are served by smaller independent alarm dealers that do not have a monitoring station and, therefore, subcontract monitoring services from Protection One. Of the approximately 10% of Protection One's customer base that are wholesale customers, approximately 75% of those are residential customers. Strategy: Protection One's strategy is to become the largest provider of life safety and property monitoring services based in North America and Europe. Protection One intends to achieve its growth objectives by extending its leadership position in large and growing residential markets and adding new customers through its Dealer Program, "tuck-in" acquisitions, direct sales and strategic alliances. Protection One believes that this strategy will lead to continued growth in sales; earnings before interest, taxes, depreciation and amortization; and earnings. Protection One is focused on: - Adding new customers at lowest cost by developing new channels of distribution - Continuing to improve its operating efficiency and margins through further integration of acquired accounts and better scale of economies - Enhancing revenues and margins by offering additional services to new and existing customers - Cross-selling value-added services to customers in each of its divisions - Continuing to improve its customer service - Building a preeminent brand name in the security industry Protection One's Dealer Program consists of independent companies with residential and small commercial sales marketing and installation skills that enter into exclusive contracts with Protection One to provide it with new monitoring customers for purchase on an ongoing basis. Since November 1997, Protection One has completed in excess of 30 transactions, adding approximately one million new customers and establishing its premier market position. Acquisitions, in conjunction with the Dealer Program, allow Protection One to increase customer density, which results in significant operating synergies. Protection One's acquisition strategy for 1999 and beyond is to focus on smaller, less expensive, "tuck-in" acquisitions that can be quickly and easily integrated into its existing operations. Strategic alliances provide Protection One with a proprietary source of prospective customers and offer it the opportunity to generate new customers at a substantially lower cost as well as advertise and build the Protection One brand name. Protection One has aggressively pursued alliances with companies in other industries that have significant residential customer bases. Approximately 95% of Protection One's strategic alliances are exclusive arrangements governed by written contracts. Examples of companies with which Protection One has established strategic alliances include electric and gas utilities, home builders, realtors, mortgage companies and home improvement retailers. The Security Alarm Industry: The North American alarm industry is large, growing rapidly and characterized by a high degree of fragmentation, has low residential penetration and is continuing a trend towards consolidation. Protection One believes the European market is similarly fragmented and that the residential customer class in Europe is substantially less penetrated than in North America. In fact, Protection One believes that the residential penetration rate in the European alarm market today closely resembles the residential penetration rate in the North American alarm market in the early 1980s. Large and Growing Market: Protection One estimates that the North American security industry grew 8.6% in 1998, reaching total revenues of approximately $16.75 billion. Of this total, Protection One estimates that recurring alarm monitoring and leasing revenue comprised 20%, or approximately $3.4 billion, an increase of 10.7% from $3.1 billion in 1997. Protection One also participates in the recurring service and maintenance sector of the alarm industry, which comprised 19%, or approximately $3.2 billion total industry revenues, an increase of 8.9% from $2.9 billion in 1997. The aggregate growth of the markets in which Protection One operates was 9.8% in 1997. SDM Magazine (formerly Security Distribution and Marketing) reports that the largest 100 companies in the United States alarm industry experienced growth of 14.8% in 1998, compared to the industry growth rate of 8.6%. This disparity reflects the ongoing consolidation of the security alarm industry as larger firms continue to actively acquire smaller companies. Protection One believes that several favorable demographic trends, including the aging of the United States population, two-income families, home officing, as well as, the increased perception of crime and a strong economy have all contributed to an increased demand for security alarm services. Increased Residential Penetration in North America and Europe: Protection One and other industry sources estimate that there will be a substantial number of new residential customers created in North America and Europe over the next several years as more and more consumers elect to include home security in their places of living. As the following chart indicates, only about 11% of the 122 million households in North America currently have a monitored alarm system. With the estimated terminal penetration in each customer class defined as the maximum alarm penetration potential within each customer class - Protection One estimates that there will be approximately 30-40 million new customers created in the residential market over the next several years: Customer Number of Customers % % Terminal Class (in millions) Penetrated Penetration Single Family 78 15% 30-40% Multifamily High Rise 12 - N/A Multifamily "Garden Style" 22 5 20-30 Manufactured Housing 10 2 10-20 Total 122 11% 20-30% The residential penetration of alarms in European households is estimated by Protection One to be less than 5%. With a population of over 380 million people in the 15 European Union countries (over 100 million larger than the United States) and crime rates in most European Union countries generally higher than the United States in most categories except murder, Protection One believes the residential alarm penetration rate in Europe will increase significantly over the next several years. Protection One currently operates in six European countries with a combined population of over 232 million. Trend Toward Consolidation: Over the last several years, many of the largest security alarm companies in North America and Europe have been acquired leaving few large national and Pan-European alarm companies. Potential new entrants into the alarm industry are now faced with few, if any, major alarm companies available for purchase. Protection One believes that larger, more cost efficient alarm companies with access to capital will continue to grow faster than the industry average. In most cases, the installation of security systems requires alarm companies to fund the excess of installation-related costs over installation revenues, a trend that continues to be prevalent in both the residential and commercial customer classes. In addition, Protection One believes the growth in false alarms is causing some municipalities to consider alternatives to response by municipal police. To the extent municipalities elect to require some form of private verification of an alarm prior to police dispatch, such policies could impose additional expenses on alarm monitoring companies and provide additional impetus for consolidation. Due to Protection One's size, density in key markets and access to capital, Protection One believes it is well positioned to take advantage of consolidation opportunities in the industry. Operations: Security alarm systems include devices installed at customers' premises designed to detect or react to conditions such as intrusion or the presence of fire or smoke. Protection One's alarm monitoring customer contracts generally have initial terms ranging from one to five years in duration, and provide for automatic renewal for a fixed period (typically one year) unless Protection One or the customer elects to cancel the contract at the end of its term. Protection One maintains eight major service centers in North America to provide monitoring services to the majority of its customer base. Through a service center in Orlando, Florida, Protection One provides wholesale monitoring services to independent dealers. Under the typical arrangement, dealers subcontract monitoring services to Protection One, primarily because such dealers do not have their own monitoring capabilities. Protection One's customer care centers are co-located in its service centers and process non-emergency communications. Operators receive inbound customer calls and the customer service group addresses customer questions and concerns about billing, service, credit and alarm activation issues. Dealer Marketing: In the last two years, Protection One has substantially increased its advertising and marketing efforts to support the Dealer Program. The Dealer Program offers dealers a wide variety of support services to assist dealers as they grow their businesses. On behalf of the Dealer Program participants, Protection One obtains purchase discounts on security systems, coordinates cooperative dealer advertising and provides administrative, marketing and employee training support services. Protection One believes that these cost savings and services would not be available to Dealer Program participants on an individual basis. Dealer contracts provide for the purchase of the dealers' customer accounts by Protection One on an ongoing basis. The dealers install specified alarm systems (which have a Protection One logo on the keypad), arrange for customers to enter into Protection One alarm monitoring agreements, and install Protection One yard signs and window decals. In addition, Protection One requires dealers to qualify prospective customers by meeting a minimum credit standard. Branch Sales: The most common reason for the loss of customers is customers moving out of their homes and businesses. Sales professionals and centralized telesales representatives at Protection One's branch offices and Chatsworth, California customer service center are responsible for tracking previous customers' homes to sign up new owners when they move into such homes. Competition: The security alarm industry is highly competitive and highly fragmented in both North America and Europe. In North America, there are only five national alarm companies that offer services across the United States and Canada with the remainder being either large regional or small, privately held alarm companies. Based on number of customers, the top five alarm companies in North America, as estimated by Protection One are: (1) ADT Security Services, a subsidiary of Tyco International, Inc. (ADT) (2) Protection One (3) SecurityLink from Ameritech, Inc., a subsidiary of Ameritech Corporation (4) Brinks Home Security Inc., a subsidiary of The Pittston Services Group of North America (5) Honeywell Inc. In Europe, Protection One competes with ADT, SecurityLink from Ameritech, Initial Shorrock (Rentokil Initial PLC) and Chubb Group Services Ltd. (Williams PLC), as well as the securities subsidiaries of Securitas AB. Other alarm service companies have adopted a strategy similar to Protection One's that entails the purchase of alarm monitoring accounts both through acquisitions of account portfolios and through dealer programs. Some competitors have greater financial resources than Protection One, or may be willing to offer higher prices than Protection One is prepared to offer to purchase customer accounts. The effect of such competition may be to reduce the purchase opportunities available to Protection One, thus reducing Protection One's rate of growth, or to increase the price paid by Protection One for customer accounts, which would adversely affect Protection One's return on investment in such accounts and Protection One's results of operations. Competition in the security alarm industry is based primarily on reliability of equipment, market visibility, services offered, reputation for quality of service, price and the ability to identify and solicit prospective customers as they move into homes. Protection One believes that it competes effectively with other national, regional and local security alarm companies due to its reputation for reliable equipment and services, its prominent presence in the areas surrounding its branch offices, its ability to offer combined monitoring, repair and enhanced services, its low cost structure and its marketing alliances. Intellectual Property: Protection One owns trademarks related to the name and logo for Protection One, Network Multifamily Security and CET, as well as a variety of trade and service marks related to individual services Protection One provides. Protection One owns certain proprietary software applications, which Protection One uses to provide services to its customers. Regulatory Matters: A number of local governmental authorities have adopted or are considering various measures aimed at reducing the number of false alarms. Such measures include: - Subjecting alarm monitoring companies to fines or penalties for transmitting false alarms - Permitting of individual alarm systems and the revocation of such permits following a specified number of false alarms - Imposing fines on alarm customers for false alarms - Imposing limitations on the number of times the police will respond to alarms at a particular location after a specified number of false alarms - Requiring further verification of an alarm signal before the police will respond Protection One's operations are subject to a variety of other laws, regulations and licensing requirements of both domestic and foreign federal, state and local authorities. In certain jurisdictions, Protection One is required to obtain licenses or permits, to comply with standards governing employee selection and training, and to meet certain standards in the conduct of its business. Many jurisdictions also require certain employees to obtain licenses or permits. Those employees who serve as patrol officers are often subject to additional licensing requirements, including firearm licensing and training requirements in jurisdictions in which they carry firearms. The alarm industry is also subject to requirements imposed by various insurance, approval, listing, and standards organizations. Depending upon the type of customer served, the type of security service provided, and the requirements of the applicable local governmental jurisdiction, adherence to the requirements and standards of such organizations is mandatory in some instances and voluntary in others. Protection One's advertising and sales practices are regulated in the United States by both the Federal Trade Commission and state consumer protection laws. In addition, certain administrative requirements and laws of the foreign jurisdictions in which Protection One operates also regulate such practices. Such laws and regulations include restrictions on the manner in which Protection One promotes the sale of its security alarm systems, the obligation to provide purchasers of its alarm systems with certain rescission rights and certain foreign jurisdictions' restrictions on a company's freedom to contract. Protection One's alarm monitoring business utilizes telephone lines and radio frequencies to transmit alarm signals. The cost of telephone lines, and the type of equipment which may be used in telephone line transmission, are currently regulated by both federal and state governments. The operation and utilization of radio frequencies are regulated by the Federal Communications Commission and state public utilities commissions. In addition, the laws of certain foreign jurisdictions in which Protection One operates regulate the telephone communications with the local authorities. Risk Management: The nature of the services provided by Protection One potentially exposes it to greater risks of liability for employee acts or omissions, or system failure, than may be inherent in other businesses. Substantially all of Protection One's alarm monitoring agreements, and other agreements, pursuant to which Protection One sells its products and services, contain provisions limiting liability to customers in an attempt to reduce this risk. Protection One's alarm response and patrol services require its employees to respond to emergencies that may entail risk of harm to such employees and to others. Protection One employs over 100 patrol and alarm response officers who are subject to extensive pre-employment screening and training. Officers are subject to local and federal background checks and drug screening before being hired, and are required to have gun and baton permits and state and city guard licenses. Officers also must be licensed by states to carry firearms and to provide patrol services. Although Protection One conducts extensive screening and training of its employees, the nature of patrol and alarm response service subjects it to greater risks related to accidents or employee behavior than other types of businesses. Protection One carries insurance of various types, including general liability and errors and omissions insurance in amounts Protection One considers adequate and customary for its industry and business. Protection One's loss experience, and that of other security service companies, may affect the availability and cost of such insurance. Certain insurance policies, and the laws of some states, may limit or prohibit insurance coverage for punitive or certain other types of damages, or liability arising from gross negligence. GEOGRAPHIC INFORMATION Geographic information is set forth in Note 19 of the Notes to Consolidated Financial Statements included herein. RISK FACTORS In connection with the KCPL merger, please consider the following: Uncertainty Regarding Trading Prices of Westar Energy Common Stock Following the KCPL Merger: Upon consummation of the KCPL merger, KCPL common shareholders will receive, among other things, shares of Westar Energy common stock in exchange for shares of KCPL common stock. There has been no public trading market for the shares of Westar Energy common stock . We and Westar Energy will apply for listing of the Westar Energy common stock on the New York Stock Exchange. However, there can be no assurance that an active trading market will develop or, if a trading market develops, that such market will be maintained. There can be no assurance of the prices at which the Westar Energy common stock will trade and such trading prices may be higher or lower than those indicated by a public market valuation analysis or a discounted cash flow valuation analysis. The trading price of the Westar Energy common stock will be determined in the marketplace and may be influenced by many factors, including, among others, Westar Energy's performance, investor expectations for Westar Energy, investor expectations of the dividend payout of comparable electric utility companies, the trading volume in Westar Energy common stock, interest rates and general economic and market conditions. The fact that Westar Energy is controlled by a significant shareholder may cause Westar Energy to trade at a discount to its valuation. No Operating History as an Independent Company: Westar Energy does not have an operating history as a unified entity. Westar Energy also will have a new management team comprised primarily of members of management of KPL, KCPL and KGE, in place at the commencement of its operation as a public company. KPL and KGE have historically relied on Western Resources for various financial and administrative services. After the KCPL Merger, Westar Energy will require its own lines of credit, banking relationships and administrative functions. Although we and KCPL believe that Westar Energy will operate efficiently as a public corporation following consummation of the KCPL Merger, there can be no such assurance. Uncertainty Regarding Volatility of Western Resources Common Stock Price: There may be a significant time delay between the date on which our shareholders and KCPL's shareholders voted for approval of the matters presented at their respective special meetings and the date of the Western Resources stock distribution. During this time delay, our common stock price may be affected by general market conditions and other economic and business factors causing the conversion ratio and the related value of our common stock per share of KCPL common stock to fluctuate. Assuming that the Western Resources index price ranges from $29.78 to $58.47, the conversion ratio per share could range from .722 to .449 and the implied value per share of the Western Resources common stock to holders of KCPL common stock could range from $21.50 to $26.25. Uncertainty Regarding Western Resources' Regulatory Status: Under the terms of the KCPL merger agreement, the electric utility operations of Western Resources will be transferred to KGE. It is a condition to our obligation to consummate this transfer that we be reasonably satisfied that following the transfer, KGE will be exempt from all of the provisions of the Public Utility Holding Company Act of 1935 (1935 Act) other than Section 9(a)(2). We anticipate that, following consummation of the KCPL Merger, it will be exempt under Section 3(a)(1) of the 1935 Act pursuant to Rule 2 thereunder from all provisions of the 1935 Act except Section 9(a)(2). To qualify for an exemption under Section 3(a)(1) of the 1935 Act, Westar Energy must be predominantly intrastate in character and carry on its utility business substantially in the state in which both we and Westar Energy are incorporated, Kansas. As a result of the KCPL Merger, Westar Energy will derive utility revenues from outside of the state of Kansas in an amount at the high-end of the range of out-of-state utility revenues of utility subsidiaries of holding companies that have claimed exemption from the 1935 Act under Section 3(a)(1) pursuant to Rule 2, which permits a company to claim exemption by making an annual filing with the SEC. Although we anticipate that after the KCPL Merger we will qualify for an exemption under Section 3(a)(1) of the 1935 Act pursuant to Rule 2, there can be no assurance that the SEC will not challenge our filing pursuant to Rule 2. Nothing in the Merger Agreement would prevent us from becoming a registered holding company following the consummation of the KCPL Merger. If we were to become a registered holding company, we and our subsidiary companies would be subject, in whole or in part, to extensive regulatory and reporting requirements under the 1935 Act, relating to, among other things, the issue and sale of securities, various charter amendments, the acquisition of any securities or utility assets or any interest in another business, the disposition of utility assets, certain proxy solicitations, intrasystem financings and other affiliated transactions. Uncertainty Regarding Future Dividend Policies: Pursuant to the Merger Agreement, the dividend policy of Westar Energy will initially be set by the Westar Energy Board of Directors so as to achieve a payout ratio that is consistent with comparable electric utility companies. There can be no assurance, however, as to the level of Westar Energy dividend following the KCPL Merger. The dividend policy of Westar Energy will also be dependent upon economic conditions, profitability and other factors which will be considered by the Westar Energy Board of Directors from time to time. Moreover, our Board of Directors will set Western Resources' dividend policy and there can be no assurance as to the level of our dividend following the KCPL Merger. Regulated Industry: Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services, as well as KCPL's and other utilities are initiating steps that are expected to result in a more competitive environment for utilities services. Increased competition may create greater risks to the stability of utility earnings. In a deregulated environment, formerly regulated utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits as competitors gain access to their service territories. This anticipated increased competition for retail electricity sales may in the future reduce Westar Energy's earnings. In addition, consummation of the KCPL Merger requires the approval of certain regulatory authorities, including the FERC. We and KCPL currently contemplate that the KCPL Merger could be completed by the end of 1999; however, there can be no assurance that we will have received all required regulatory approvals prior to that time. Nor can there be any assurance that the KCPL Merger will be consummated or, if consummated, that it will occur by the end of 1999. Control by the Principal Shareholder of Westar Energy: Upon consummation of the KCPL Merger, we will own, assuming there are no dissenting shares, 80.1% of the diluted outstanding shares of Westar Energy common stock. As a result of the KCPL Merger, we will generally be able to control the vote on all matters submitted to a vote of the holders of shares of outstanding Westar Energy common stock, including the election of Westar Energy's directors, amendments to the Westar Energy Articles of Incorporation and Westar Energy Bylaws and approval of significant corporate transactions and other actions pertaining to Westar Energy which require approval of Westar Energy's shareholders. Notwithstanding this fact, we agreed to certain arrangements relating to the election of directors of Westar Energy after the closing of the KCPL Merger. Additionally, we will be in a position to prevent a takeover of Westar Energy by one or more third parties, which could deprive Westar Energy's shareholders of a control premium that might otherwise be realized by them in connection with an acquisition of Westar Energy. Westar Energy presently expects to apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to its electric generation, transmission and distribution operations. See Stranded Costs in Management's Discussion and Analysis. Regulatory changes, including competition, could adversely impact our, Westar Energy's, and KCPL's ability to recover our investment in these assets. As of December 31, 1998, Western Resources and KCPL have recorded regulatory assets of approximately $364 million and $135 million, which are currently subject to recovery in future rates. Of this amount, approximately $205 million and $109 million, are receivables for future income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs including coal contract settlement costs, deferred plant costs and debt issuance costs. In a competitive environment, we, Westar Energy and KCPL may not be able to fully recover our entire investment in Wolf Creek. We and KCPL each presently owns 47% of Wolf Creek, and following the KCPL Merger, Westar Energy will own 94% 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, KCPL or Westar Energy determine that we have stranded costs and cannot recover our investment in these assets, our future net utility income may be lower that our historical net utility income unless we can compensate for the loss of such income with other measures. For risk factors relating to Protection One, see its December 31, 1998 Annual Report on Form 10-K. EXECUTIVE OFFICERS OF THE COMPANY

Executive officers serve at the pleasure of the Board of Directors. There are no family relationships among any of the executive officers, nor any arrangements or understandings between any executive officer and other persons pursuant to which he was appointed as an executive officer. ITEM 2. PROPERTIES ELECTRIC UTILITY OPERATIONS Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (1) Abilene Energy Center: Combustion Turbine 1 1973 Gas 66 Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 152 2 1967 Gas--Oil 382 Hutchinson Energy Center: Steam Turbines 1 1950 Gas 18 2 1950 Gas 18 3 1951 Gas 28 4 1965 Gas 191 Combustion Turbines 1 1974 Gas 50 2 1974 Gas 49 3 1974 Gas 52 4 1975 Diesel 78 Diesel Generator 1 1983 Diesel 3 Jeffrey Energy Center (84%)(2): Steam Turbines 1 1978 Coal 617 2 1980 Coal 622 3 1983 Coal 621 La Cygne Station (50%)(2): Steam Turbines 1 1973 Coal 343 2 1977 Coal 334 Lawrence Energy Center: Steam Turbines 2 1952 Gas 0 (3) 3 1954 Coal 59 4 1960 Coal 119 5 1971 Coal 394 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 Turbines 3 1954 Gas--Oil 0 (3) Tecumseh Energy Center: Steam Turbines 7 1957 Coal 85 8 1962 Coal 153 Combustion Turbines 1 1972 Gas 20 2 1972 Gas 21 Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) (1) Wichita Plant: Diesel Generator 5 1969 Diesel 3 Wolf Creek Generating Station (47%)(2): Nuclear 1 1985 Uranium 547 Total 5,356 (1) Based on MOKAN rating. (2) The company jointly owns Jeffrey Energy Center (84%), La Cygne Station (50%) and Wolf Creek Generating Station (47%). KCPL jointly owns 50% of La Cygne Station and 47% of Wolf Creek Generating Station. (3) These units have been "mothballed" for future use. The company owns approximately 6,300 miles of transmission lines, approximately 21,300 miles of overhead distribution lines, and approximately 4,200 miles of underground distribution lines. The company has all franchises necessary to sell electricity within the territories from which substantially all of its gross operating sales are derived. MONITORED SERVICES Protection One operates primarily from the following facilities, although Protection One leases office space for its 66 service branch offices and 4 satellites in 33 states and Canada, 7 branch offices in the United Kingdom and 42 in continental Europe. Size Principal Location (Sq. ft.) Lease/Own Purpose United States: Addison, TX. . . . 28,512 Lease Service Center/ Administrative Headquarters Beaverton, OR. . . 44,600 Lease Service Center Chatsworth, CA . . 43,472 Lease Customer Service Center Culver City, CA. . 23,520 Lease Corporate Headquarters Culver City, CA. . 8,029 Lease Administrative Functions Hagerstown, MD . . 21,370 Lease Service Center Irving, TX . . . . 53,750 Lease Service Center Irving, TX . . . . 54,394 Lease Financial/ Administrative Headquarters Orlando, FL. . . . 11,020 Lease Wholesale Service Center Wichita, KS. . . . 50,000 Own Service Center Canada: Ottawa, ON . . . . 7,937 Lease Administrative Headquarters Vancouver, BC. . . 5,177 Lease Monitoring and Service Center Europe: Basingstoke, UK. . 3,500 Lease Financial/ Administrative Headquarters Size Principal Location (Sq. ft.) Lease/Own Purpose Paris, FR. . . . . 3,498 Lease Financial/ Administrative Headquarters Vitrolles (Marseilles) FR. . 6,813 Lease Administrative/Service Center FINANCING Our ability to issue additional debt and equity securities is restricted under limitations imposed by the charter and the Mortgage and Deed of Trust of Western Resources and KGE. Western Resources' mortgage prohibits additional Western Resources first mortgage bonds from being issued (except in connection with certain refundings) unless our net earnings available for interest, depreciation and property retirement for a period of 12 consecutive months within 15 months preceding the issuance are not less than the greater of twice the annual interest charges on, 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, $200 million of first mortgage bonds could be issued (7.00% interest rate assumed). Western Resources' 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 $283 million of net bondable property additions not subject to an unfunded prior lien entitling us to issue up to $169 million principal amount of additional bonds. As of December 31, 1998, no first mortgage bonds could be issued on the basis of retired bonds. KGE's mortgage prohibits additional KGE first mortgage bonds from being issued (except in connection with certain refundings) unless KGE's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. Based on KGE's results for the 12 months ended December 31, 1998, approximately $1.1 billion principal amount of additional KGE first mortgage bonds could be issued (7.00% interest rate assumed). KGE's 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, KGE had approximately $1.5 billion of net bondable property additions not subject to an unfunded prior lien entitling KGE to issue up to $1 billion principal amount of additional KGE bonds. As of December 31, 1998, $17 million in additional bonds could be issued on the basis of retired bonds. The most restrictive provision of our charter permits the issuance of additional shares of preferred stock without certain specified preferred stockholder approval only if, for a period of 12 consecutive months within 15 months preceding the issuance, net earnings available for payment of interest exceed one and one-half times the sum of annual interest requirements plus dividend requirements on preferred stock after giving effect to the proposed issuance. After giving effect to the annual interest and dividend requirements on all debt and preferred stock outstanding at December 31, 1998, such ratio was 1.19 for the 12 months ended December 31, 1998. In connection with the combination of the electric utility operations of Western Resources, KCPL and KGE, Westar Energy will assume $1.9 billion of indebtedness for borrowed money of Western Resources and KGE comprised primarily of the companies' outstanding long-term debt. In connection with the transfer of Western Resources' electric utility operations, which constitutes all of the property subject to the Mortgage and Deed of Trust, dated July 1, 1939, (Mortgage) between us and Harris Trust and Savings Bank, as trustee, and substantially all of the assets of Western Resources, to Westar Energy, we in accordance with the Mortgage will assign and be released from, and Westar Energy will assume, the Mortgage and all of our obligations under the Mortgage and all first mortgage bonds outstanding thereunder. Pursuant to the amended and restated agreement and plan of merger, KGE's mortgage, by operation of law, will be assumed by Westar Energy. We will not transfer and will continue to hold our investments in unregulated operations, including Protection One and ONEOK. See, Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 21 of Notes to Consolidated Financial Statements. KCPL has outstanding first mortgage bonds (the "KCPL Bonds") which are secured by a lien on substantially all of KCPL's fixed property and franchises purported to be conveyed by the General Mortgage Indenture and Deed of Trust and the various Supplemental Indentures creating the KCPL Bonds (collectively, the "KCPL Mortgage"). Westar Energy has agreed to assume $800 million of debt from KCPL. The KCPL mortgage will have a prior lien on the KCPL property and franchises to be owned by Westar Energy. ITEM 3. LEGAL PROCEEDINGS On January 8, 1997, Innovative Business Systems, Ltd. (IBS) filed suit against the company and Westinghouse Electric Corporation (WEC), Westinghouse Security Systems, Inc. (WSS) and WestSec, Inc. (WestSec), a wholly-owned subsidiary of the company established to acquire the assets of WSS, in Dallas County, Texas district court (Cause No 97-00184) alleging, among other things, breach of contract by WEC and interference with contract against the company in connection with the sale by WEC of the assets of WSS to the company. On November 9, 1998, WEC settled this matter and the litigation was dismissed. The Securities and Exchange Commission (SEC) has commenced a private investigation relating, among other things, to the timeliness and adequacy of disclosure filings with the SEC by the company with respect to securities of ADT Ltd. The company is cooperating with the SEC staff relating to the investigation. The company understands that class action lawsuits relating to the Protection One restatement of 1997 and 1998 financial statements and subsequent decrease in stock price were recently filed naming Protection One, Western Resources and certain officers of Protection One. The company has not yet been served with a copy of the lawsuits. The company cannot predict the outcome or the effect of this litigation. Additional information on legal proceedings involving the company is set forth in Notes 3 and 10 of Notes to Consolidated Financial Statements included herein. See also Item 1. Business, Environmental Matters and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted during the fourth quarter of the fiscal year covered by this report to a vote of the company's security holders, through the solicitation of proxies or otherwise. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Stock Trading Western Resources' common stock, which is traded under the ticker symbol WR, is listed on the New York Stock Exchange. As of April 1, 1999, there were 54,290 common shareholders of record. For information regarding quarterly common stock price ranges for 1998 and 1997, see Note 22 of Notes to Consolidated Financial Statements included herein. Dividends Western Resources' common stock is entitled to dividends when and as declared by the Board of Directors. At December 31, 1998, the company's retained earnings were restricted by $857,600 against the payment of dividends on common stock. However, prior to the payment of common dividends, dividends must be first paid to the holders of preferred stock based on the fixed dividend rate for each series. Dividends have been paid on the company's common stock throughout the company's history. Quarterly dividends on common stock normally are paid on or about the first of January, April, July, and October to shareholders of record as of or about the third day of the preceding month. Dividends increased four cents per common share in 1998 to $2.14 per share. The Company's currently authorized quarterly dividend for 1999 is 53 1/2 cents per common share or $2.14 on an annual basis is paid from its earnings and remains unchanged from 1998. The company's board of directors reviews its dividend policy on an annual basis. The company expects the next review to be made in January 2000. Among the factors typically considered in determining its dividend policy are earnings, cash flows, capitalization ratios, competition and regulatory conditions. In addition, the company expects the board of directors in its next review to consider various factors such as greater participation in its dividend reinvestment program, its new compensation plan that pays senior management part of their annual compensation in stock and its business profile upon completion of the KCPL merger. For information regarding quarterly dividend declarations for 1998 and 1997, see Note 22 of Notes to Consolidated Financial Statements included herein. See also Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. ITEM 6. SELECTED FINANCIAL DATA

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 Western Resources, Inc. and its subsidiaries. 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 Consolidated Statements of Income on page 63. 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 Consolidated 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, ability to enter new markets successfully and capitalize on growth opportunities in nonregulated businesses, events in foreign markets in which investments have been made, 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 Continued Expansion of Monitored Services Protection One, Inc. (Protection One) had a year of rapid expansion and continued growth. During the year, Protection One doubled the size of its customer base from about 750,000 customers to about 1.5 million customers. This growth was achieved through acquisitions and Protection One's Dealer Program. During 1998, Protection One invested approximately $549 million in security company acquisitions. Highlights of this activity include: - Network Multi-Family - A leading provider of monitored services to multi-family dwellings. This acquisition added approximately 200,000 customers. - Multimedia Security Services - A purchase of assets, including a large security monitoring center in Wichita, Kansas, that added about 147,000 customers. - Compagnie Europeenne de Telesecurite (CET) - An acquisition of a French monitored services provider which added 60,000 customers and established a major presence in Western Europe. Protection One financed these acquisitions primarily with cash advances from Western Resources and from the sale of common shares. In June, Protection One completed an equity offering that raised approximately $406 million in aggregate proceeds. We purchased approximately 37.6 million Protection One common shares of the 42.8 million common shares sold. The shares, which sold for $9.50 per common share, increased our investment in Protection One by $357 million. Our approximate 85% investment in Protection One totals about $1.1 billion at December 31, 1998. During the year, Protection One refinanced a large portion of its debt by issuing $250 million of senior unsecured notes, issuing $350 million of senior subordinated notes and obtaining a $500 million credit facility. Part of the proceeds from these offerings were used to repay a $395 million intercompany obligation to us. The Lifeline Transaction In October 1998, Protection One announced an agreement to acquire Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal emergency response and support services in North America. Based on the average closing price for the three trading days prior to April 8, 1999, the value of the consideration to be paid under the merger agreement is approximately $129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has advised Protection One that it is evaluating the restatement of Protection One's financial statements. The consideration to be given in the Lifeline transaction is by design variable and is subject to change within certain parameters until the closing date. Interested parties should obtain the most recent proxy/registration statement for further analysis of the transaction. Investment in ONEOK, INC. We received approximately $40 million in cash dividends from our ONEOK, Inc. (ONEOK) investment in 1998. Tax rules allow us to exclude 70% of these dividends from the determination of taxable income. This 70% exclusion saves us about $11 million in income taxes annually. In December 1998, ONEOK announced its intention to purchase Southwest Gas Corporation (Southwest). ONEOK will pay Southwest shareholders $28.50 per common share and assume debt for a total transaction value of approximately $1.8 billion. ONEOK will add 1.2 million customers in higher growth markets in Arizona, Nevada and California to its existing base of 1.4 million customers as a result of this purchase. The merger is expected to create the largest stand-alone gas distribution company in the United States. In February 1999, ONEOK was advised by Southwest that it had received an unsolicited offer of $32 per share of common stock from Southern Union Company. Southwest is evaluating both offers. In November 1997, we completed our strategic alliance with ONEOK and contributed substantially all of our natural gas business to ONEOK in exchange for a 45% ownership interest in ONEOK. Our ownership interest is comprised of approximately 3.2 million common shares and approximately 20.1 million convertible preferred shares. If all the preferred shares were converted, we would own approximately 45% of ONEOK's common shares presently outstanding. Following the strategic alliance, the consolidated energy sales, related cost of sales and operating expenses in 1997 for our natural gas business have been replaced by investment earnings in ONEOK. Electric Utility Operations We experienced warmer weather during the summer months in 1998 than we did in 1997 which improved net income by $19.8 million. The effect of our electric rate decrease lowered 1998 net income $6.6 million. In January 1997, the Kansas Corporation Commission (KCC) entered an order reducing electric rates for both our KPL division (KPL) and Kansas Gas and Electric Company (KGE). Significant terms of the order are as follows: - We made permanent the May 1996 interim $8.7 million decrease in KGE rates on February 1, 1997 - We reduced KGE's rates by $36 million annually on February 1, 1997 - We reduced KPL's rates by $10 million annually on February 1, 1997 - We rebated $5 million to all of our electric customers in January 1998 - We reduced KGE's rates by $10 million annually on June 1, 1998 - We rebated $5 million to all of our electric customers in January 1999 - We will reduce KGE's rates by $10 million more annually on June 1, 1999 These electric rate decreases have negatively impacted our net income. The total annual cumulative effect of these rate decreases is approximately $75 million. All rate decreases are cumulative. Rebates are one-time events and do not influence future rates. Electric utility net income totaled approximately $133 million, excluding one-time events, for 1998. Electric utility net income reflects a debt allocation of $1.9 billion. Westar Energy, the new company to be created as a result of the Kansas City Power & Light Company (KCPL) merger, will assume $1.9 billion of debt from us and KGE after closing the KCPL merger. We expect to own an 80.1% interest in Westar Energy which will combine our electric operations with those of KCPL. For more information on the KCPL merger, see OTHER INFORMATION. Charge to Income to Exit International Power Development Activity We decided to exit the international power development business during the fourth quarter of 1998 in order to focus more attention on our consumer service businesses. As a result of this decision, we recorded a charge to income approximating $99 million, or $0.98 per share. The charge accrued exit and shutdown costs, including severance to affected employees who were notified of the shutdown in December, recognized the write-off of deferred development costs for projects we will cease developing and recognized the write-off of goodwill created when we acquired The Wing Group in 1996. We have also written down the value of certain equity investments in foreign countries to their estimated fair value. We believe negative political, economic, operating, and regulatory factors reduced the value of our ownership interests in these investments and that this decrease is not temporary. See Note 11 for further information. Other Charges to Income In the fourth quarter, we sold our investment in an equity security that was unrelated to our core utility and monitored services businesses and realized a pre-tax loss of about $13 million. In addition, we wrote down the value of another investment due to declines in value which we believe were not temporary. The pre-tax charge related to this investment approximated $6 million. Operating results for 1998 also included pre-tax severance obligations and employee benefits of approximately $20 million. Operating Results Operating results for 1998 are difficult to compare to 1997 due primarily to 1998 charges as discussed above in 1998 HIGHLIGHTS and the 1997 pre-tax gain on the sale of Tyco International Ltd. (Tyco) common stock of $864 million. In addition to the gain on the sale of Tyco common stock recorded in 1997, we recorded charges which included $48 million of deferred KCPL merger costs and approximately $24 million recorded by Protection One to recognize higher than expected customer attrition and to record costs related to the acquisition of Protection One. In November 1997, we completed our strategic alliance with ONEOK and contributed substantially all of our natural gas business to ONEOK in exchange for a 45% ownership interest in ONEOK. Following the strategic alliance, the consolidated sales, related cost of sales and operating expenses in 1997 for our natural gas business have been replaced in 1998 by investment earnings from ONEOK. Sales and cost of sales from our natural gas business in 1997 were $739 million and $538 million. The following explains significant changes from prior year results in sales, cost of sales, operating expenses, other income (expense), interest expense, income taxes, and preferred and preference dividends. Energy sales primarily include electric sales, power marketing sales and, through November 1997, natural gas sales. Items included in energy cost of sales are fuel expense, purchased power expense (including electricity we purchase from others for resale), power marketing expense and, through November 1997, natural gas purchased. Electric Utility Sales Electric sales include sales from fossil generation, power marketing and power delivery operations. The KCC and the Federal Energy Regulatory Commission (FERC) authorize rates for our electric sales. Power marketing is only regulated by the FERC. Our electric sales vary with levels of energy deliveries. Changing weather affects the amount of electricity our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand. Many things will affect our future electric 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: Total electric sales increased 31%. Electric utility sales increased 6% due to increased retail energy deliveries as a result of warmer summer temperatures and power marketing sales increased 448%. Our annual $10 million electric rate decrease implemented on June 1, 1998, 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. . . . . 9.5% Commercial . . . . . 6.8% Industrial . . . . . 1.6% Other. . . . . . . . 1.0% Total retail . . . 5.9% 1997 compared to 1996: Electric sales increased 3% because of our expansion of power marketing activity in 1997. Higher electric sales from power marketing were offset by our reduced electric rates implemented February 1, 1997, which lowered revenues by an estimated $46 million annually. Cost of Sales 1998 compared to 1997: Total electric cost of sales increased 83% in 1998 due mostly to higher power marketing cost of sales. 1997 compared to 1996: Our power marketing activity in 1997 increased electric cost of sales by $70 million. Actual cost of fuel to generate electricity (coal, nuclear fuel, natural gas or oil) and the amount of power purchased from other utilities were $14 million higher. For further explanations of cost of sales increases, see the fossil generation and nuclear generation business segments discussion below. Depreciation and Amortization Expense 1998 compared to 1997: Depreciation and amortization expense decreased $22 million, or 12%, primarily because we had fully amortized a regulatory asset during 1997. This decrease in amortization expense increased 1998 earnings before interest and taxes from 1997. 1997 compared to 1996: Depreciation and amortization expense increased $13 million, or 8%, primarily due to fully amortizing a regulated asset associated with Wolf Creek nuclear generation facility (Wolf Creek). 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 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 $364 million. Of this amount, $205 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 including coal contract settlement costs, deferred employee benefit 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. Our ownership would increase to 94% when the KCPL combination is completed. We also may 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 utility income will be lower than our historical net utility income has been unless we compensate for the loss of such income with other measures. Electric Utility Business Segments We define and report our business segments based on how management currently evaluates our business. Management has segmented our business based on differences in products and services, production processes and management responsibility. We manage our electric utility business segments' performance based on their earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by generally accepted accounting principles, should not be construed as an alternative to operating income and 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, dividends 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 power delivery segment that are allocated to our fossil generation and nuclear generation business segments based on demand and energy cost. The following discussion identifies key factors affecting our electric business segments. Fossil Generation 1998 1997 1996 (Dollars in Thousands) External sales. . . . . . . . . $525,974 $208,836 $144,056 Allocated sales . . . . . . . . 517,363 517,167 518,199 Depreciation and amortization . 53,132 53,831 52,303 EBIT. . . . . . . . . . . . . . 144,357 149,825 188,173 External sales increased over the last two years mostly because of increased power marketing sales of $313 million in 1998 and $70 million in 1997. In 1997, we made a strategic decision to expand our power marketing business to better utilize our generating assets and reduce risk associated with energy prices. We expanded into both the marketing of electricity and risk management services to wholesale electric customers and the purchase of electricity for our retail customers. Our margin from power marketing activities is significantly less than our margins on our traditional electric sales. Our power marketing activity has resulted in electric purchases and sales made in areas outside of our historical marketing territory. Through December 31, 1998, our power marketing activity has had an insignificant effect on EBIT. The availability of our generating units and purchased power from other companies impacts power marketing sales. 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 experienced 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 and impact our ability to participate in power trades. EBIT for 1998 decreased from 1997 because we had higher purchased power expense of $5 million due to a coal-fired generation station being unavailable for the summer. EBIT for 1997 decreased from 1996 due to higher cost of fuel and purchased power expense discussed below, a $6 million expense of obsolete inventory and other increased operating and maintenance expenses. In 1997, actual cost of fossil fuel to generate electricity and the amount of power purchased from other utilities were $14 million higher 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 generation station was off-line during 1997 for an extended maintenance outage. As a result, we 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. Railroad transportation limitations prevented scheduled fuel deliveries, reducing our coal inventories. To compensate for a lack of coal, we purchased more power from other utilities and burned more expensive natural gas to meet our energy requirements. We also purchased more power from other utilities because our Wolf Creek and La Cygne generating stations were not generating electricity for parts of 1997. 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. 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 10). Power Delivery 1998 1997 1996 (Dollars in Thousands) External sales. . . . . . . . . $1,085,711 $1,021,212 $1,053,359 Allocated sales . . . . . . . . 66,492 66,492 71,492 Depreciation and amortization . 68,297 63,590 60,713 EBIT. . . . . . . . . . . . . . 196,398 173,809 218,936 External sales and EBIT increased from 1997 to 1998. In addition to our normal customer growth, we experienced warmer weather during the summer months in 1998 than we did in 1997 which improved external sales approximately $42 million. The effect of our electric rate decrease lowered 1998 external sales approximately $11 million. External sales and EBIT decreased from 1996 to 1997 due to reduced electric rates implemented February 1, 1997, which lowered revenues by an estimated $46 million. Monitored Services 1998 1997 1996 (Dollars in Thousands) External sales. . . . . . . . . $421,095 $152,347 $8,546 Depreciation and amortization . 117,651 41,179 944 EBIT. . . . . . . . . . . . . . 56,727 (38,517) (3,555) Restatement of 1997 Financial Statements: As a result of a decision by Protection One to restate its 1997 financial statements, we have chosen to restate our financial statements to conform to the changes reflected by Protection One. We do not believe the restated operating results and financial position are materially different from those which were reported in our December 31, 1997, Annual Report on Form 10K/A. See Note 2 to the consolidated financial statements for further discussion of the restatement. 1998 compared to 1997: In 1998, Protection One operated and managed our monitored services interests. The results discussed below reflect Protection One on a stand-alone basis and do not take into consideration the minority interest of about 15% at December 31, 1998. Results of operations for 1998 reflect adjustments made to restate quarterly earnings as discussed in Note 22 to the consolidated financial statements. Monitored services business sales increased $269 million. The increase is due to acquisitions and new customers purchased through Protection One's Dealer Program. The Dealer Program consists of independent companies with residential and small commercial sales, marketing and installation skills provide Protection One with new monitoring customers for purchase on an ongoing basis. Monthly recurring revenue represents the monthly fees paid by customers for on-going monitored security service. At December 31, 1998, monthly recurring revenue totaled about $38 million. Protection One added approximately $17 million of monthly recurring revenue from acquisitions and approximately $5 million of monthly recurring revenue from its Dealer Program. Because acquisitions and purchases from the Dealer Program occurred throughout the year, not all of the $22 million of acquired monthly recurring revenue is reflected in 1998 results. Offsetting these revenue increases was Protection One's net monthly recurring revenue attrition of 9%, a decrease from 13% in 1997 (see further discussion below). Cost of sales increased $93 million. Monitoring and related services expenses increased by $71 million, or 217%, due to the acquisition of three major service centers and three smaller satellite monitoring facilities in the United States, as well as two service centers in Canada and two in Europe. Monitoring and service activities at existing facilities increased as well due to new customers generated by Protection One's Dealer Program. Selling, general and administrative expenses rose $31 million. The increase in expenses resulted primarily from acquisitions, offset by a decrease in sales and related expenses. Selling, general and administrative expenses as a percentage of total revenues declined from 56% in 1997 to 27% in 1998. The transition of Protection One's primary distribution channel from an internal sales force to the Dealer Program resulted in sales commissions declining by approximately $9 million. Protection One also reduced advertising and telemarketing activities that formerly supported the internal sales force. Amortization of intangibles and depreciation expense totaled $118 million in 1998. Protection One recorded $582 million of customer intangibles and $549 million in cost allocated to goodwill during 1998 from its purchases of monitored services companies, portfolios of customer accounts and individual new customers through its Dealer Program. Protection One amortizes customer accounts over 10 years and goodwill over 40 years, in each case using a straight-line method. Like most monitored services companies, Protection One invests significant amounts to generate new customers and seeks to maintain relationships with its customers by providing excellent service. Protection One measures the loss of customers and revenues to verify that investments in new customers are generating a satisfactory rate of return and that the policy of amortizing the cost to acquire customer accounts over 10 years is reasonable. Protection One calculates both gross customer losses and net monthly recurring revenue loss as meaningful statistics. If future losses were to increase substantially, Protection One could be required to shorten the 10-year period used to amortize the investment in new customers. The resulting increase in amortization expense could be significant. In addition, the SEC staff is reviewing Protection One's amortization methodology used on customer accounts. The SEC staff has questioned the appropriateness of the current accounting method which Protection One believes is consistent with industry practices. A significant change in the amortization method would likely have a material effect on the company's results of operations. The intangible amortization represents a non-cash charge to income. The net balance of customer accounts at December 31, 1998, was approximately $1 billion. EBIT increased $95 million in 1998. Included in 1998 EBIT is a non-recurring gain approximating $16 million on the repurchase of customer contracts covered by a financing arrangement. A charge of approximately $24 million adversely affected 1997 EBIT. The charge was needed to recognize higher than expected customer attrition and to record costs related to the acquisition of Protection One. 1997 compared to 1996: Monitored services business sales increased $144 million from a minimal amount recorded in 1996. This increase is because of our December 30, 1996, purchase of the net assets of Westinghouse Security Systems, Inc. (Westinghouse Security Systems) and the acquisition on November 24, 1997, of 82.4% of Protection One. Other Operating Expenses In 1998, we recorded a $99 million charge to income associated with our decision to exit the international power project development business as previously discussed in 1998 HIGHLIGHTS. In 1997, we recorded a charge totaling $48 million to write-off the original merger costs associated with the KCPL transaction. In addition, Protection One recorded a charge of $24 million in 1997 as discussed above in Monitored Services. Other Income (Expense) Other income (expense) includes miscellaneous income and expenses not directly related to our operations. 1998 compared to 1997: Other income (expense) decreased $866 million due to the following factors: (Millions) Other Income (Expense) in 1997 . . . . . . . . $ 922 1997 Non-recurring gain on the sale of our TYCO common stock. . . . . . . . . . . . (864) Investment earnings recorded on Hanover and ADT investments. . . . . . . . . . . (33) 1998 Increase in earnings from the investment in ONEOK . . . . . . . . . . . . . . . . 37 Recorded investment losses . . . . . . . . (22) Non-recurring Protection One gains. . . . . 19 Increase in COLI death proceeds . . . . . . 13 Other miscellaneous . . . . . . . . . . . . (16) Other income (expense) in 1998. . . . . . . $56 Interest Expense 1998 compared to 1997: Interest expense represents the interest we paid on outstanding debt. Interest expense increased 17% due to higher long-term debt. Our long-term debt balance increased $875 million due to our and Protection One's issuance of new long-term debt used to reduce existing short-term debt, to fund nonregulated operations and to finance a substantial portion of Protection One's customer account growth. Lower short-term debt interest expense partially offset the higher long-term debt interest expense. Our short-term debt had a lower weighted average interest rate than the long-term debt which replaced it. 1997 compared to 1996: We incurred $27 million more short-term debt interest in 1997. Average short-term debt balances were higher in 1997 because we used short-term debt to finance our investment in ADT Limited (which later converted to Tyco) and to purchase the assets of Westinghouse Security Systems. Short-term debt interest expense declined in the second half of 1997 after we used the proceeds from the sale of Tyco common stock and a long-term debt financing to reduce our short-term debt balance. From December 31, 1996, to December 31, 1997, our short-term debt balance decreased $744 million. From 1996 to 1997, interest recorded on long-term debt increased $14 million, or 13%, due to the issuance of $520 million in senior unsecured notes. Income Taxes 1998 compared to 1997: Income tax expense declined significantly due to the decline in taxable net income. In 1998, charges, primarily the charge to income to exit the international power development business, significantly lowered tax expense. Tax expense for 1997 included taxes related to the gain on the sale of Tyco common stock. Our effective tax rate also declined from 1997. This decline is largely attributable to non-taxable proceeds from our corporate-owned life insurance policies and the benefit of excluding 70% of ONEOK dividends received from the determination of taxable income. Non-deductible goodwill amortization, state income taxes, depreciation, and other adjustments to our tax provision partially offset the tax benefits described above. 1997 compared to 1996: Income taxes on the gain from the sale of Tyco common stock increased total income tax expense by approximately $345 million. Preferred and Preference Dividends On April 1, 1998, we redeemed the 7.58% preference stock due 2007. On July 1, 1996, we redeemed all the 8.5% preference stock due 2016. These redemptions have resulted in a significant decline in preferred and preference dividends since 1996. In accordance with the terms of the KCPL merger agreement, we will be required to redeem all of the remaining preferred stock prior to the merger. LIQUIDITY AND CAPITAL RESOURCES Overview Most of our cash requirements consist of capital expenditures and maintenance costs associated with the electric utility business, continued growth in the monitored services business and payment of common stock dividends. Our ability to attract necessary financial capital on reasonable terms is critical to our overall business plan. Historically, we have paid for acquisitions with cash on hand, or the issuance of stock or short-term debt. Our ability to provide the cash, stock or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions. As of December 31, 1998, we had $16 million in cash and cash equivalents. We consider highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Other than operations, our primary source of short-term cash is from short-term bank loans, unsecured lines of credit and the sale of commercial paper. At December 31, 1998, we had approximately $313 million of short-term debt outstanding, of which $148 million was commercial paper and $165 million was bank loans. We have arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $821 million. We have also registered securities for sale with the Securities and Exchange Commission. As of December 31, 1998, these included $400 million of unsecured senior notes, $50 million of KGE first mortgage bonds and approximately 11 million Western Resources common shares. Our embedded cost of long-term debt was 7.4% at December 31, 1998, a drop of 0.1% from December 31, 1997. Cash Flows from Operating Activities Cash from operations increased significantly from 1997 because of two factors. First, taxes paid of approximately $345 million on the gain on the sale of Tyco common stock reduced 1997 operating cash flow. Secondly, 1998 includes the first full year of Protection One operations. This increased operating cash flow from our monitored services business by about $90 million from 1997. Cash Flows from Investing Activities During 1998, most of our cash used for investing purposes was to continue the growth of our monitored services business. We used net cash of about $827 million to expand this business through acquisitions, the Dealer Program and installations. Protection One does not anticipate its 1999 expansion activity to be as significant as in 1998. Capital expenditures totaled $183 million in 1998, slightly less than 1997 and 1996. We also purchased marketable securities and additional interests in affordable housing tax credits. In October 1998, Protection One announced an agreement to acquire Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal emergency response and support services in North America. Based on the average closing price for the three trading days prior to April 8, 1999, the value of the consideration to be paid under the merger agreement is approximately $129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has advised Protection One that it is evaluating the restatement of Protection One's financial statements. The consideration to be given in the Lifeline transaction is by design variable and is subject to change within certain parameters until the closing date. Interested parties should obtain the most recent proxy/registration statement for further analysis of the transaction. On January 25, 1999, Protection One's Board of Directors authorized a private placement of common shares to Westar Capital, Inc., a wholly-owned subsidiary of our company. The private placement will allow us to maintain ownership in excess of 80% of Protection One's issued and outstanding common shares following the issuance of Protection shares to Lifeline shareholders. We may also acquire shares of Protection One common stock in open market or privately negotiated transactions depending upon market conditions. Any open market or private purchases will reduce or eliminate our need to purchase shares in the private placement to maintain our ownership of at least 80%. Cash Flows from Financing Activities In July 1998, we issued $30 million of 6.8% Senior Notes due July 15, 2018. The notes are unsecured and unsubordinated obligations of the company. In July 1998, we filed a shelf registration for $800 million in senior, unsecured obligations of the company. In August 1998, we issued $400 million of 6.25% Putable/Callable Notes due on August 15, 2018, putable/callable on August 15, 2003 under this shelf registration. Proceeds from these issuances were used to reduce short-term debt incurred in connection with investments in unregulated operations, the redemption of preferred securities and other general corporate purposes. On April 1, 1998, we redeemed our 7.58% Preference Stock due 2007 at a premium, including dividends, for $53 million. Financing activities provided Protection One with $744 million of cash. Protection One raised $642 million through the following new debt instruments: (Dollars in Millions) August 17, 1998: Senior unsecured 7 3/8% notes due in 2005 . . . . . . . . . . . $250 December 16, 1998: Senior subordinated 8 1/8% notes due in 2009 . . . . . . . . . . . 350 December, 1998: Borrowings under a revolving credit facility. . . . . . . . . . . 42 $642 In December 1998, Protection One obtained a revolving credit facility. Protection One can borrow under this facility at a range of interest rates based on either (1) the Prime Rate or (2) a Eurodollar Rate. At December 31, 1998 the senior credit facility had a weighted average interest rate of 6.8% and had an outstanding balance of $42 million. The facility matures in December 2001. Among other restrictions, Protection One is required under the revolving credit facility to maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of not less than 2.75 to one and total debt cannot be greater than 5 times annualized most recent quarter EBITDA for 1999 and 4.5 times thereafter. In addition, in light of the restatement of its financial statements, Protection One has obtained a bank waiver for prior representations concerning its financial statements. Protection One also raised $406 million in aggregate proceeds through the sale of common stock. We paid approximately $357 million of the total amount raised; therefore, the proceeds net of applicable fees obtained from the sale of common stock approximated $46 million. Protection One used proceeds from these financing transactions primarily to fund acquisitions and Dealer Program growth. Protection One also repaid $512 million of existing debt, including a $395 million intercompany obligation with us. Capital Structure Our capital structures at December 31, 1998, and 1997 were as follows: 1998 1997 Common stock . . . . . . . . . . . . . . . 37% 45% Preferred and preference stock . . . . . . 1% 2% Western Resources obligated mandatorily redeemable preferred securities of subsidiary trust holding solely company subordinated debentures . 4% 5% Long-term debt . . . . . . . . . . . . . . 58% 48% 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 and principal on these securities. These ratings affect how much we will have to pay as interest on securities we sell to obtain additional capital. The better the rating, the less interest we will have to pay on the new debt securities we sell. At December 31, 1998, ratings with these agencies were as follows: Kansas Gas Western Western and Electric Resources' Western Resources' Company's Mortgage Resources' Short-term Mortgage Bond Unsecured Debt Bond Rating Agency Rating Debt Rating Rating S&P A- BBB A-2 BBB+ Fitch A- BBB+ F-2 A- Moody's A3 Baa1 P-2 A3 Following the announcement of our restructured merger agreement with KCPL, S&P placed its ratings of Western Resources and KGE bonds on CreditWatch with positive implications. Moody's changed the direction of its ongoing review of Western Resources' debt rating from possible downgrade to possible upgrade. Future Cash Requirements We believe that internally generated funds and new and existing credit agreements will be sufficient to meet our operating and capital expenditure requirements, debt service and dividend 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, availability of earnings to pay dividends, 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 our electric utility operations with KCPL. In order to meet the needs of our electric utility customers, we plan to install three new combustion turbine generators for use as peaking units. The installed capacity of the three new generators will approximate 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. We estimate that the project will require $120 million in capital resources through the completion of the projects in 2001. In addition, we are planning to return our inactive generation plant in Neosho, Kansas to active service in 1999 at an estimated cost of $0.7 million. On January 4, 1999, we and the Empire District Electric Company (Empire) signed a memorandum of understanding that provides for the joint ownership of a 500-megawatt combined cycle generating unit, which Empire will operate. We estimate that the project will require $90 million in capital resources and we will own 40% of the generating unit. Construction of the unit is expected to begin in the fall of 1999 with operation beginning approximately 20 months later. 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. - Growth within the monitored services business, including acquisition of customer accounts. Capital expenditures for 1998 and anticipated capital expenditures for 1999 through 2001 are as follows: Fossil Nuclear Power Monitored Generation Generation Delivery Services Other Total (Dollars in Thousands) 1998 . . $ 46,400 $25,800 $78,000 $859,500 $47,700 $1,057,400 1999 . . 117,900 19,700 90,800 434,400 20,700 683,500 2000 . . 149,900 32,200 79,700 355,100 2,300 619,200 2001 . . 109,100 21,200 78,600 373,700 200 582,800 Monitored services capital expenditures include anticipated acquisitions and purchases of customer accounts. Other primarily represents our commitments to our Affordable Housing Tax Credit (AHTC) program. See discussion in OTHER INFORMATION below. These estimates are prepared for planning purposes and may be revised (see Note 10). Actual expenditures may differ from our estimates. Electric expenditures shown in the table above do not take into account the pending combination of our electric utility operations with KCPL (see Note 21). Bond maturities will require cash of approximately $435 million through the year 2003. Protection One is required to retire its $500 million revolving credit facility in the year 2001. At December 31, 1998, $42 million was outstanding under this facility. Dividend Policy Our currently authorized quarterly dividend for 1999 of 53 1/2 cents per common share or $2.14 on an annual basis is paid from our earnings and remains unchanged from 1998. Our board of directors reviews our dividend policy on an annual basis. We expect the next review to be made in January 2000. Among the factors typically considered in determining our dividend policy are earnings, cash flows, capitalization ratios, competition and regulatory conditions. In addition, we expect the board of directors in its next review to consider various factors such as greater participation in our dividend reinvestment program, our new compensation plan that pays senior management part of their annual compensation in stock and our business profile upon completion of the KCPL merger. 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 KGE 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 12% of total electric sales, excluding power marketing 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 legislation in Kansas remains uncertain. We believe successful providers of energy in a deregulated market will provide energy-related services. We believe consumers will demand innovative options and insist on efficient products and services to meet their energy-related needs. We believe that our strong core utility business provides a platform to offer the efficient energy products and services that customers will desire. We continue to seek new ways to add value to the lives and businesses of our customers. We recognize that our current customer base must expand beyond our existing service area. 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 range from 73% to 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, common dividends 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. To better position ourselves for the competitive energy environment, we are pursuing a merger with KCPL, we have consummated a strategic alliance with ONEOK (see Note 8) and we hold a controlling interest in Protection One (see Note 4). In light of competitive developments, we are pursuing the following strategic plan: - Maintain a strong core energy business. - Seek out and pursue business lines that are compatible with our investment criteria and growth strategies; i.e., customer growth and monthly, recurring revenues. - Promote cross-marketing strategies among our consumer services businesses. Year 2OOO Issue We 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 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. Electric Utility Operations: We have recognized the potential adverse effects the Year 2000 Issue could have on our utility operations. 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 business units and departments of our utility operations, using a common methodology. The Year 2000 Issues concerning the Wolf Creek nuclear operating plant are discussed 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. Most 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, we believe we are approximately 74% complete with our readiness efforts. The estimated progress of our departments and business units, exclusive of Protection One and Wolf Creek Nuclear Operating Corporation (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, 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 for utility operations were substantially completed at the end of 1998 except for those items scheduled for normal maintenance or upgrade during 1999. We estimate that total costs to update all of our electric utility operating systems for Year 2000 readiness, excluding costs associated with WCNOC discussed below, to be approximately $6.5 million, of which $4.2 million represents IT costs and $2.3 million represents non-IT costs. As of December 31, 1998, we have expended 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 we know, we expect to incur the remaining $2.4 million, of which $1.0 million represents IT costs and $1.4 million represents non-IT costs, by the end of 1999. These costs include labor costs for both company 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. 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 affecting 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 62% of our generating capacity utilizes coal as fuel. 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 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 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 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. - 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 worst 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.

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. Monitored Services Operations: Protection One is reviewing its computer programs, computer hardware and embedded systems critical to its businesses and operational needs to identify and correct any components that could be affected by the change of the date to January 1, 2000. Protection One will continue its reviews until January 1, 2000, particularly with respect to the acquisition of businesses that include additional computer systems and equipment. In addition, changes in the date of compliance or preparedness within companies that provide services or equipment to Protection One will require management to continue its evaluations. Protection One's Year 2000 readiness program addresses: - Commercial computer software, including mainframe, client/service and desktop software - Internally developed computer software, including mainframe, client/ server and desktop software - Computer hardware, including mainframe, client/server and desk top, network, communications, and peripherals - Devices using embedded computer chips, including controls, sensors, facilities equipment, heating, ventilating and air conditioning equipment - Relationships with third-party vendors and suppliers Based on the results of its on-going reviews, Protection One believes that the Year 2000 Issue does not pose material operational problems. However, the most reasonably likely worst case scenario is to be found in the area of external services, specifically firms providing electrical power, heating, ventilating and air conditioning, and local and long distance telecommunications. While Protection One believes the total collapse of service provided is highly unlikely, one or more of the following scenarios could occur: - Temporary disruption or unpredictable provision of nationwide long- distance service - Temporary or unpredictable provision of local telephone service, or - Temporary interruption or unpredictable provision of electrical power. To the extent customers did not receive timely and adequate responses to alarms, Protection One would be required to rely on its specific disclaimer, in most of its customers agreements of liability for the acts or omissions of third party agencies. The enforcability of such disclaimers may be subject to judicial scrutiny in jurisdictions in which Protection One operates. Protection One estimates the total cost to update all critical operating systems for Year 2000 readiness will be approximately $5 million. At December 31, 1998, approximately $1.1 million of these costs had been incurred. The costs of the Year 2000 project and the date on which Protection One plans to complete the Year 2000 modifications, estimated to be during 1999, is based on the best estimates, which were derived utilizing numerous assumptions of future events including the continued availability of certain resources, third party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved and actual results could differ materially from those plans. Specific factors that might cause such material differences include, but are not limited to, the availability and cost of personnel trained in this area, the ability to locate and correct all relevant computer codes, and similar uncertainties. Market Risk Disclosure Market Price Risks: We are exposed to market risk, including changes in commodity prices, equity and debt instrument investment prices and interest rates. Commodity Price Exposure: In our commodity price risk management activities, we engage in both trading and non-trading activities. In these activities, we utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps which require payments (or receipt of payments) from counterparties based on the differential between specified prices for the related commodity, and futures traded on electricity and natural gas. We are involved in trading activities primarily to minimize risk from market fluctuations, to maintain a market presence and to enhance system reliability. Although we attempt to balance our physical and financial purchase and sale contracts in terms of quantities and contract terms, net open positions can exist or are established due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have an open position, we are exposed to the risk that fluctuating market prices may adversely impact our financial position or results from operations. We manage and measure the exposure of our trading portfolio using a variance/covariance value-at-risk (VAR) model, which simulates forward price curves in the energy markets to estimate the size of future potential losses. The quantification of market risk using VAR methodologies provides a consistent measure of risk across diverse energy markets and products. The use of this method requires a number of key assumptions including the selection of a confidence level for losses and the estimated holding period. We express VAR as a potential dollar loss based on a 95% confidence level using a one-day holding period. As of December 31, 1998, our VAR (unaudited) for our trading activities was approximately $100,000. Our Risk Oversight Committee sets the VAR limit. We employ additional risk control mechanisms such as stress testing, daily loss limits, and commodity position limits. We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks which management policy dictates. The counterparties in our portfolio consist primarily of large energy marketers and major utility companies. The creditworthiness of our counterparties could impact our overall exposure to credit risk, either positively or negatively. However, we maintain credit policies with regard to our counterparties that in our management's view minimize overall credit risk. We are also exposed to commodity price changes outside of trading activities. We use derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of cash market prices. Given the amount of power purchased for utility operations during 1998, we would have had exposure of approximately $5 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, we had exposure of approximately $4 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. Investment Portfolio: We have approximately $288 million of equity and debt securities as of December 31, 1998. We do not hedge these investments and are exposed to the risk of changing market prices. We classify these securities as "available for sale" for accounting purposes and mark them to market on the balance sheet at the end of each period. However, net income is not affected until the securities are sold. Management estimates that its investments will generally be consistent with trends and movements of the overall stock market barring any unusual situations. An immediate 10% change in the market price of our equity securities would have a $13 million effect on other comprehensive income. The value of the debt securities in our portfolio changes inversely with fluctuations in interest rates. Interest Rate Exposure: We have approximately $602 million of variable rate debt, including current maturities of fixed 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 $5 million. Merger Agreement with Kansas City Power & Light Company On February 7, 1997, we signed a merger agreement with KCPL by which KCPL would be merged with and into the company in exchange for company stock. In December 1997, representatives of our 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, we and KCPL agreed to a restructuring of our 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, our electric utility operations will be transferred to KGE, and KCPL and KGE will be merged into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive company common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of company 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 company common stock on the New York Stock Exchange 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, we 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 KGE. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of Western Resources and KGE, and $800 million of debt of KCPL. Long-term debt of the company, excluding Protection One, was $2.5 billion at December 31,1998. Under the terms of the merger agreement, it is intended that we will be released from our obligations with respect to our debt to be assumed by Westar Energy. Pursuant to the merger agreement, we have agreed, among other things, to call for redemption all outstanding shares of our 4 1/2% Series Preferred Stock, par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per share, and 5% Series Preferred Stock, par value $100 per share. Consummation of the merger is subject to customary conditions. On July 30, 1998, our shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. We estimate 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 we believe would make the merger uneconomical. The merger agreement allows us to terminate the agreement if regulatory approvals are not acceptable. 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. We do not anticipate the proposed legislation to pass in its current form. We are 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, we and KCPL filed an amended application with the FERC to approve the Western Resources/KCPL merger and the formation of Westar Energy. We have 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 us 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. We are 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 KGE have joint interests in certain electric generating assets, including Wolf Creek. For additional information, see Note 21. 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 almost 8,800 megawatts of electricity. At December 31, 1998, we 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. Affordable Housing Tax Credit Program In 1997, we received authorization from the KCC to invest up to $114 million in AHTC investments. An example of an AHTC project is housing for residents who are elderly or meet certain income requirements. At December 31, 1998, we had invested approximately $65 million to purchase limited partnership interests. We are committed to investing approximately $25 million more in AHTC investments by April 1, 2001. These investments are accounted for using the equity method of accounting. Based upon an order received from the KCC, income generated from the AHTC investments, primarily tax credits, will be used to offset costs associated with postretirement and postemployment benefits offered to our employees. Pronouncements Issued but Not Yet Effective 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. SFAS 133 is effective for fiscal years beginning after June 15, 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 and other comprehensive income. In December 1998, the Emerging Issues Task Force reached consensus on Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 98-10). EITF Issue 98-10 is effective for fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in the fair value included in earnings. The company will adopt EITF Issue 98-10 during 1999. Management does not expect the impact of adopting EITF Issue 98-10 to be material to the company's financial position or results of operations. 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. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS PAGE Report of Independent Public Accountants 61 Financial Statements: Consolidated Balance Sheets, December 31, 1998 and 1997 62 Consolidated Statements of Income for the years ended December 31, 1998, 1997 and 1996 63 Consolidated Statements of Comprehensive Income for the years ended December 31, 1998, 1997 and 1996 64 Consolidated Statements of Cash Flows for the years ended 1998, 1997 and 1996 65 Consolidated Statements of Cumulative Preferred and Preference Stock, December 31, 1998 and 1997 66 Consolidated Statements of Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 67 Notes to Consolidated Financial Statements 68 Financial Schedules: Schedule II - Valuation and Qualifying Accounts 110 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, III, IV, and V. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Western Resources, Inc.: We have audited the accompanying consolidated balance sheets and statements of cumulative preferred and preference stock of Western Resources, Inc., and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, comprehensive income, cash flows, and shareholders' equity for each of the three years in the period ended December 31, 1998. (1997 restated, see Note 2.) These consolidated financial statements and the schedule referred to below are the responsibility of the company's management. Our responsibility is to express an opinion on these consolidated financial statements and this schedule 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 consolidated financial position of Western Resources, Inc., and subsidiaries as of December 31, 1998 and 1997, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. Schedule II - Valuation and Qualifying Accounts is presented for purposes of complying with the Securities and Exchange Commission rules and is not part of the basic financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Kansas City, Missouri, January 27, 1999 (Except with respect to the matter discussed in Note 2, as to which the date is April 5, 1999) WESTERN RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands)

WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts)

WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in Thousands)

WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands)

WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CUMULATIVE PREFERRED AND PREFERENCE STOCK (Dollars in Thousands)

WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands)

WESTERN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Business: Western Resources, Inc. (the company) is a publicly traded consumer services company. The company's primary business activities are providing electric generation, transmission and distribution services to approximately 620,000 customers in Kansas and providing monitored services to approximately 1.5 million customers in North America, the United Kingdom and Continental Europe. In addition, through the company's 45% ownership interest in ONEOK, Inc. (ONEOK), natural gas transmission and distribution services are provided to approximately 1.4 million customers in Oklahoma and Kansas. Rate regulated electric service is provided by KPL, a division of the company and Kansas Gas and Electric Company (KGE), a wholly-owned subsidiary. Monitored services are provided by Protection One, Inc. (Protection One), a publicly-traded, approximately 85%-owned subsidiary. Principles of Consolidation: The company prepares its financial statements in conformity with generally accepted accounting principles. The accompanying consolidated financial statements include the accounts of Western Resources and its wholly-owned and majority-owned subsidiaries. All material intercompany accounts and transactions have been eliminated. Common stock investments that are not majority-owned are accounted for using the equity method when the company's investment allows it the ability to exert significant influence. 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. 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. 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. Available-for-sale Securities: The company classifies marketable equity securities accounted for under the cost method as available-for-sale. These securities are reported at fair value based on quoted market prices. Cumulative unrealized gains and losses, net of the related tax effect, are reported as a separate component of shareholders' equity until realized. Current changes in unrealized gains and losses are reported as a component of other comprehensive income. At December 31, 1998, an unrealized gain of $10 million (net of deferred taxes of $12 million) was included in shareholders' equity. These securities had a fair value of approximately $288 million and a cost of approximately $266 million at December 31, 1998. At December 31, 1997, an unrealized gain of $12 million (net of deferred taxes of $13 million) was included in shareholders' equity. These securities had a fair value of approximately $75 million and a cost of approximately $50 million at December 31, 1997. Property, Plant and Equipment: Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering, supervision, general and administrative costs and an allowance for funds used during construction (AFUDC). The AFUDC rate was 6.00% in 1998, 5.80% in 1997 and 5.70% in 1996. The cost of additions to utility plant 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 value are charged to accumulated depreciation. Inventories and supplies for the company's utility business are stated at average cost. In accordance with regulatory decisions made by the Kansas Corporation Commission (KCC), the acquisition premium of approximately $801 million resulting from the acquisition of KGE in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization as of December 31, 1998 and 1997 totaled $68.0 million and $47.9 million, respectively. Depreciation: Utility plant is depreciated on the straight-line method at rates approved by regulatory authorities. Utility plant is depreciated on an average annual composite basis using group rates that approximated 2.88% during 1998, 2.89% during 1997 and 2.97% during 1996. Nonutility property, plant and equipment of approximately $62 million at December 31, 1998 is depreciated on a straight-line basis over the estimated useful lives of the related assets. 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 million and $20.9 million, respectively. Customer Accounts: Customer accounts are stated at cost. The cost includes amounts paid to dealers and the estimated fair value of accounts acquired in business acquisitions. Internal costs incurred in support of acquiring customer accounts are expensed as incurred. The cost of customer accounts is amortized on a straight-line basis over a 10-year period. It is Protection One's policy to evaluate acquired customer account loss on a quarterly basis utilizing historical loss rates for the customer accounts in total and, when necessary, adjust amortization over the remaining useful life. The Securities and Exchange Commission (SEC) staff has questioned the appropriateness of the current accounting method which Protection One believes is consistent with industry practices. A significant change in the amortization method would likely have a material effect on the company's results of operations. The accumulated amortization of customer accounts as of December 31, 1998 and 1997 was approximately $117 million and $29 million, respectively. Goodwill: Goodwill, which represents the excess of the purchase price over the fair value of net assets acquired, is generally amortized on a straight-line basis over 40 years. The accumulated amortization of goodwill as of December 31, 1998 and 1997 approximated $32 million and $9 million, respectively. Regulatory Assets and Liabilities: Regulatory assets represent probable future revenue 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 were 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 Consolidated 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 consolidated financial statements are as follows: December 31, 1998 1997 (Dollars in Thousands) Recoverable taxes. . . . . . . . . . . . $205,416 $212,996 Debt issuance costs. . . . . . . . . . . 73,635 75,336 Deferred employee benefit costs. . . . . 36,128 37,875 Deferred plant costs . . . . . . . . . . 30,657 30,979 Coal contract settlement costs . . . . . 12,259 16,032 Other regulatory assets, . . . . . . . . 6,118 7,203 Total regulatory assets . . . . . . . . $364,213 $380,421 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 employee benefit costs: Deferred employee benefit costs are expected to be recovered from income generated through the company's Affordable Housing Tax Credit investment program. Deferred plant costs: Disallowances related to the Wolf Creek nuclear generating facility. Coal contract settlement costs: The company deferred costs associated with the termination of certain coal purchase contracts. These costs are being amortized over periods ending in 2002 and 2013. The company expects to recover all of the above regulatory assets in rates. A return is allowed on deferred plant costs and coal contract settlement costs and approximately $53 million of debt issuance costs. Minority Interests: Minority interests represent the minority shareholders' proportionate share of the shareholders' equity and net income of Protection One. Sales: Energy 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 $39 million and $37 million are recorded as a component of accounts receivable (net) on the Consolidated Balance Sheets at December 31, 1998 and 1997, respectively. Security sales are recognized when installation of an alarm system occurs and when monitoring or other security-related services are provided. The company's allowance for doubtful accounts receivable totaled $29.5 million and $8.4 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. Affordable Housing Tax Credit Program (AHTC): The company has received authorization from the KCC to invest up to $114 million in AHTC investments. At December 31, 1998 and 1997, the company had invested approximately $65 million and $17 million to purchase AHTC investments in limited partnerships. The company is committed to investing approximately $25 million more in AHTC investments by April 1, 2001. These investments are accounted for using the equity method. Based upon an order received from the KCC, income generated from the AHTC investments, primarily tax credits, will be used to offset costs associated with postretirement and postemployment benefits offered to the company's employees. Risk Management: The company is involved in trading activities primarily to minimize risk from market fluctuations, maintain a market presence and to enhance system reliability. In these activities, the company utilizes a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps which require payments (or receipt of payments) from counterparties based on the differential between specified prices for the related commodity and futures traded on electricity and natural gas. For the company's trading operation, the company accounts for these transactions at the time of delivery or settlement, accruing in the interim only for net losses as they become evident on firm purchase commitments. Cash Surrender Value of Life Insurance: The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other long-term assets on the Consolidated Balance Sheets at December 31: 1998 1997 (Dollars in Millions) Cash surrender value of policies. . . . $587.5 $547.7 Borrowings against policies . . . . . . (558.5) (524.3) COLI (net). . . . . . . . . . . . . . . $ 29.0 $ 23.4 Income is recorded for increases in cash surrender value and net death proceeds for approximately 83% of the cash surrender value and 85% of the policy borrowings at December 31, 1998. 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. The balance of the policies were acquired to mitigate the cost of postretirement and postemployment benefits, in accordance with an order from the KCC. New Pronouncements: Effective January 1, 1998, the company adopted the provisions of Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" (SFAS 130). This statement establishes standards for reporting and display of comprehensive income and its components. 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, 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 and other comprehensive income. In December 1998, the Emerging Issues Task Force reached consensus on Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 98-10). EITF Issue 98-10 is effective for fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in the fair value included in earnings. The company will adopt EITF Issue 98-10 during 1999. Management does not expect the impact of adopting EITF Issue 98-10 to be material to the company's financial position or results of operations. Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 2. RESTATEMENT OF 1997 FINANCIAL STATEMENTS As a result of a decision by Protection One, an 85 percent owned subsidiary, to restate its 1997 financial statements, the company has chosen to restate its 1997 financial statements to conform to the changes adopted by Protection One. This restatement resulted from decisions by Protection One: - To expense as incurred, yard signs, including those which were removed and replaced, following the decision to transition all monitored services operations to the Protection One brand in the fourth quarter of 1997. The costs of this yard sign change-out had previously been estimated and accrued at December 31, 1997. This adjustment increased previously reported net income by approximately $5.7 million and decreased current liabilities by $12.3 million at December 31, 1997. - To adjust certain purchase price allocations, reverse amounts which had previously been accrued to transition new customers and adjust an obligation to repurchase certain customer accounts sold under a financing agreement to estimated fair value. These adjustments reduced net income by approximately $0.3 million and reduced current liabilities by approximately $22.2 million at December 31, 1997. The total effect of the 1997 restatement was to increase previously reported net income in 1997 by approximately $5.4 million ($0.08 per common share) and increase previously reported retained earnings at December 31, 1997, by the same amount. The restatement did not impact previously reported sales and does not impact the company's net cash flow. (See Note 22 for the impact of the restatement on quarterly results for 1998). 3. LEGAL PROCEEDINGS On January 8, 1997, Innovative Business Systems, Ltd. (IBS) filed suit against the company and Westinghouse Electric Corporation (WEC), Westinghouse Security Systems, Inc. (WSS) and WestSec, Inc. (WestSec), a wholly-owned subsidiary of the company established to acquire the assets of WSS, in Dallas County, Texas district court (Cause No 97-00184) alleging, among other things, breach of contract by WEC and interference with contract against the company in connection with the sale by WEC of the assets of WSS to the company. On November 9, 1998, WEC settled this matter and the litigation was dismissed. The SEC has commenced a private investigation relating, among other things, to the timeliness and adequacy of disclosure filings with the SEC by the company with respect to securities of ADT Ltd. The company is cooperating with the SEC staff relating to the investigation. The company understands that class action lawsuits relating to the Protection One restatement of 1997 and 1998 financial statements and subsequent decrease in stock price were recently filed naming Protection One, Western Resources and certain officers of Protection One. The company has not yet been served with a copy of the lawsuits. The company cannot predict the outcome or the effect of this litigation. The company and its subsidiaries are involved in various other 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. 4. MONITORED SERVICES BUSINESS During 1998, the company continued its growth in the monitored services business through its ownership in Protection One. Protection One experienced rapid growth in its customer base as a result of several significant acquisitions. The more significant acquisitions were Protection One's purchase of the assets of Multimedia Security Services for approximately $233 million and its purchase of the stock of Compagnie Europeenne de Telesecurite for approximately $140 million. Each acquisition was accounted for as a purchase and, accordingly, the operating results for each acquired company have been included in the company's consolidated financial statements since the date of acquisition. Total purchase consideration has been allocated to the net assets acquired based on estimates of fair value. Protection One's purchase price allocations for 1998 acquisitions are preliminary and may be adjusted as additional information is obtained. During the first quarter of 1998, the company transferred its investment in Network Multi-Family to Protection One at a cost that approximated $180 million. Consideration paid, assets acquired and liabilities assumed in connection with these and other acquisitions made by Protection One during 1998 were as follows: (Dollars in Thousands) Fair value of assets acquired, net of cash acquired . . . . . . $820,251 Cash paid, net of cash acquired. . 549,196 Total liabilities assumed. . . . . $271,055 The following table presents the unaudited pro forma financial information considering Protection One's monitored services acquisitions in 1998 and 1997. The pro forma information reflects the actual operating results of each company prior to its acquisition and includes adjustments to interest expense, intangible amortization, and income taxes. The table assumes acquisitions in 1998 occurred as of January 1, 1997. The 1997 acquisitions are assumed to have occurred on January 1, 1996. Year Ended December 31, 1998 1997 1996 (Dollars in Thousands, Except Per Share Data) (Unaudited) Sales . . . . . . . . . . . $2,175,089 $2,462,849 $2,280,122 Earnings available for common stock . . . . . . . 33,556 463,264 133,581 Earnings per share . . . . . $0.51 $7.11 $2.09 The unaudited pro forma financial information is not necessarily indicative of the results of operations had the entities been combined for the entire period nor do they purport to be indicative of results which will be obtained in the future. In October 1998, Protection One announced an agreement to acquire Lifeline Systems, Inc., (Lifeline) a leading provider of 24-hour personal emergency response and support services in North America. Based on the average closing price for the three trading days prior to April 8, 1999, the value of the consideration to be paid under the merger agreement is approximately $129.2 million or $22.05 per Lifeline share in cash and stock. Lifeline has advised Protection One that it is evaluating the restatement of Protection One's financial statements. The consideration to be given in the Lifeline transaction is by design variable and is subject to change within certain parameters until the closing date. Interested parties should obtain the most recent proxy/registration statement for further analysis of the transaction. In December 1997, Protection One incurred charges of approximately $24 million to recognize higher than expected customer attrition and record costs related to the acquisition of Protection One. These charges are as follows: Impairment of customer accounts $12,750 Protection One merger related costs: Inventory and other asset losses 3,558 Disposition of fixed assets 4,128 Closure of duplicate facilities 1,991 Severance compensation and benefits 1,865 11,542 Total charges $24,292 Impairment of customer accounts: Protection One wrote down the value of the customer base of part of its business due to excess customer losses experienced in 1997. The excess customer losses were due to (1) the effects of transitioning the customer base from one service provider to another and, (2) the relative quality of certain classes of customer accounts acquired in an acquisition due to use of a prior aggressive marketing plan accompanied by limited credit checking. Inventory and other asset losses: Protection One reduced the value of inventory held at branches due to conversion to the external Dealer Program as its primary marketing channel. Disposition of fixed assets: Protection One reduced the net book value of computer and telecommunication equipment due to plans to migrate certain monitoring, customer service and financial operations to new software and hardware platforms in the first quarter of 1998. At December 31, 1998, Protection One continued to use certain components of this equipment due to unplanned delays experienced in the implementation of replacement systems. The remaining equipment is expected to be fully retired in 1999. Closure of duplicate facilities: Protection One committed to a plan to close 38 branch locations in cities with two or more branches and where the customer base did not justify such a large presence. At December 31, 1998, all such locations were closed. The remaining amount accrued at December 31, 1998, represents obligations for vacated lease facilities and approximates $1 million. Severance compensation and benefits: Upon the company's purchase of approximately 82.4% of Protection One in November 1997, the affected employees were notified of their severance package. Actual payments approximated the amount accrued. Protection One recognized a non-recurring gain in 1998 when customer accounts were repurchased pursuant to a financing agreement. Terms of the agreement required Protection One to purchase these accounts at fair value. The purchase price negotiated was less than the estimated value. As a result, a non-recurring gain which approximated $16 million was recorded as other income. 5. RATE MATTERS AND REGULATION KCC Rate Proceedings: In January 1997, the KCC entered an order reducing electric rates for both KPL and KGE. Significant terms of the order are as follows: - The company made permanent an interim $8.7 million rate reduction implemented by KGE in May 1996. This reduction was effective February 1, 1997. - The company reduced KGE's annual rates by $36 million effective February 1, 1997. - The company reduced KPL's annual rates by $10 million effective February 1, 1997. - The company rebated $5 million to all of its electric customers in January 1998. - The company reduced KGE's annual rates by an additional $10 million on June 1, 1998. - The company rebated an additional $5 million to all of its electric customers in January 1999. - The company will reduce KGE's 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. 6. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK, AND OTHER MANDATORILY REDEEMABLE SECURITIES The company's Restated Articles of Incorporation, as amended, provide for 85,000,000 authorized shares of common stock. At December 31, 1998, 65,909,442 shares were outstanding. The company has a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP may be either original issue shares or shares purchased on the open market. The company issued original issue shares under DSPP from January 1, 1995 until October 15, 1997. Between November 1, 1997 and March 16, 1998, shares for DSPP were satisfied on the open market. All other shares have been original issue shares. During 1998, a total of 653,570 shares were issued under DSPP including 499,839 original issue shares and 153,731 shares purchased on the open market. At December 31, 1998, 591,047 shares were available under the DSPP registration statement. Preferred Stock Not Subject to Mandatory Redemption: The cumulative preferred stock is redeemable in whole or in part on 30 to 60 days notice at the option of the company. Preference Stock Subject to Mandatory Redemption: On April 1, 1998, the company redeemed the 7.58% Preference Stock due 2007 at a premium, including dividends, for $53 million. Other Mandatorily Redeemable Securities: On December 14, 1995, Western Resources Capital I, a wholly-owned trust, issued four million preferred securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, for $100 million. The trust interests represented by the preferred securities are redeemable at the option of Western Resources Capital I, on or after December 11, 2000, at $25 per preferred security plus accrued interest and unpaid dividends. Holders of the securities are entitled to receive distributions at an annual rate of 7-7/8% of the liquidation preference value of $25. Distributions are payable quarterly and in substance are tax deductible by the company. These distributions are recorded as interest expense. The sole asset of the trust is $103 million principal amount of 7-7/8% Deferrable Interest Subordinated Debentures, Series A due December 11, 2025. On July 31, 1996, Western Resources Capital II, a wholly-owned trust, of which the sole asset is subordinated debentures of the company, sold in a public offering, 4.8 million shares of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, for $120 million. The trust interests represented by the preferred securities are redeemable at the option of Western Resources Capital II, on or after July 31, 2001, at $25 per preferred security plus accumulated and unpaid distributions. Holders of the securities are entitled to receive distributions at an annual rate of 8-1/2% of the liquidation preference value of $25. Distributions are payable quarterly and in substance are tax deductible by the company. These distributions are recorded as interest expense. The sole asset of the trust is $124 million principal amount of 8-1/2% Deferrable Interest Subordinated Debentures, Series B due July 31, 2036. In addition to the company's obligations under the Subordinated Debentures discussed above, the company has agreed to guarantee, on a subordinated basis, payment of distributions on the preferred securities. These undertakings constitute a full and unconditional guarantee by the company of the trust's obligations under the preferred securities. 7. LONG-TERM DEBT The amount of the company's first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited. The amount of KGE's first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, 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 each mortgage. Debt discount and expenses are being amortized over the remaining lives of each issue. During the years 1999 through 2003, $125 million of bonds will mature in 1999, $75 million of bonds will mature in 2000, $100 million of bonds will mature in 2002 and $135 million of bonds will mature in 2003. No other bonds will mature during this time period. The company's unsecured debt represents general obligations that are not secured by any of the company's properties or assets. Any unsecured debt will be subordinated to all secured debt of the company, including it's first mortgage bonds. The notes are structurally subordinated to all secured and unsecured debt of the company's subsidiaries. Long-term debt outstanding is as follows at December 31: 1998 1997 (Dollars in Thousands) Western Resources First mortgage bond series: 7 1/4% due 1999. . . . . . . . . . . . . $ 125,000 $ 125,000 8 7/8% due 2000. . . . . . . . . . . . . 75,000 75,000 7 1/4% due 2002. . . . . . . . . . . . . 100,000 100,000 8 1/2% due 2022. . . . . . . . . . . . . 125,000 125,000 7.65% due 2023 . . . . . . . . . . . . . 100,000 100,000 525,000 525,000 Pollution control bond series: Variable due 2032 (1). . . . . . . . . . 45,000 45,000 Variable due 2032 (2). . . . . . . . . . 30,500 30,500 6% due 2033. . . . . . . . . . . . . . . 58,420 58,420 133,920 133,920 KGE First mortgage bond series: 7.60% due 2003 . . . . . . . . . . . . . 135,000 135,000 6 1/2% due 2005. . . . . . . . . . . . . 65,000 65,000 6.20% due 2006 . . . . . . . . . . . . . 100,000 100,000 300,000 300,000 Pollution control bond series: 5.10% due 2023 . . . . . . . . . . . . . 13,673 13,757 Variable due 2027 (3). . . . . . . . . . 21,940 21,940 7.0% due 2031. . . . . . . . . . . . . . 327,500 327,500 Variable due 2032 (4). . . . . . . . . . 14,500 14,500 Variable due 2032 (5). . . . . . . . . . 10,000 10,000 387,613 387,697 Western Resources 6 7/8% unsecured senior notes due 2004 . 370,000 370,000 7 1/8% unsecured senior notes due 2009 . 150,000 150,000 6.80% unsecured senior notes due 2018. . 29,985 - 6.25% unsecured senior notes due 2018, putable/callable 2003. . . . . . . . . 400,000 - 949,985 520,000 Protection One Revolving credit facility. . . . . . . . 42,417 - 6.75% unsecured convertible senior subordinated discount notes due 2003 . 53,950 102,500 13.625% unsecured senior subordinated discount notes due 2005 . 125,590 171,926 7.375% unsecured senior notes due 2005 . 250,000 - 8.125% unsecured senior subordinated notes due 2009. . . . . . 350,000 - Customer repurchase agreement, due 1998 . . . . . . . . . . . . . . . - 69,129 Recourse financing agreements (6). . . . 93,541 - Other. . . . . . . . . . . . . . . . . . 2,574 - 918,072 343,555 Other long-term agreements . . . . . . . . 8,325 4,798 Unamortized debt premium . . . . . . . . . 13,918 - Less: Unamortized debt discount . . . . . . . . (7,931) (5,719) Long-term debt due within one year . . . . (165,838) (21,217) Long-term debt (net) . . . . . . . . . . . $3,063,064 $2,188,034 Rates at December 31, 1998: (1) 3.55%, (2) 3.45%, (3) 3.50%, (4) 3.75% (5) 3.75% and (6) 15% implicit rate for operating lease agreements sold with recourse - average term approximately 4 years. Protection One maintains a $500 million revolving credit facility that expires in December 2001. Under the terms of this agreement, Protection One may, at its option, borrow at different market-based interest rates. At December 31, 1998, $42.4 million was borrowed under this facility. The senior subordinated discount notes of Protection One contain covenants which, among other matters, limit Protection One's ability to incur certain indebtedness, make restricted payments and merge, consolidate or sell assets. The convertible senior subordinated notes of Protection One are convertible at any time into common stock at a price of $11.19 per share. The indenture under which these notes were issued contains covenants which limit Protection One's ability to incur certain indebtedness. Among other restrictions, Protection One is required under the revolving credit facility to maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of not less than 2.75 to one and total debt cannot be greater than 5 times annualized most recent quarter EBITDA for 1999 and 4.5 times thereafter. In addition, in light of the restatement of its financial statements, Protection One has obtained a bank waiver for prior representations concerning its financial statements. 8. STRATEGIC ALLIANCE WITH ONEOK, INC. In November 1997, the company completed its strategic alliance with ONEOK. The company contributed substantially all of its regulated and non-regulated natural gas business to ONEOK in exchange for a 45% ownership interest in ONEOK. The company's ownership interest in ONEOK is comprised of approximately 3.2 million common shares and approximately 20.1 million convertible preferred shares. If all the preferred shares were converted, the company would own approximately 45% of ONEOK's common shares presently outstanding. The agreement with ONEOK allows the company to appoint two members to ONEOK's board of directors. The company accounts for its common ownership in accordance with the equity method of accounting. Subsequent to the formation of the strategic alliance, the consolidated energy revenues, related cost of sales and operating expenses for the company's natural gas business have been replaced by investment earnings in ONEOK. 9. SHORT-TERM DEBT The company has arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $821 million. The agreements provide the company with the ability to borrow at different market-based interest rates. The company pays commitment or facility fees in support of these lines of credit. Under the terms of the agreements, the company is required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. The unused portion of these lines of credit are used to provide support for commercial paper. In addition, the company has agreements with several banks to borrow on an uncommitted, as available, basis at money-market rates quoted by the banks. There are no costs, other than interest, for these agreements. The company also uses commercial paper to fund its short-term borrowing requirements. Information regarding the company's short-term borrowings, comprised of borrowings under the credit agreements, bank loans and commercial paper, is as follows: December 31, 1998 1997 (Dollars in Thousands) Borrowings outstanding at year end: Bank loans. . . . . . . . . . . . $164,700 $161,000 Commercial paper notes. . . . . . 147,772 75,500 Total . . . . . . . . . . . . . $312,472 $236,500 Weighted average interest rate on debt outstanding at year end (including fees). . . . . . . . . 5.94% 6.28% Weighted average short-term debt outstanding during the year . . . $529,255 $787,507 Weighted daily average interest rates during the year (including fees). . . . . . . . . 5.93% 5.93% Unused lines of credit supporting commercial paper notes. . . . . . $820,900 $772,850 10. COMMITMENTS AND CONTINGENCIES As part of its ongoing operations and construction program, the company has commitments under purchase orders and contracts which have an unexpended balance of approximately $86.9 million at December 31, 1998. Affordable Housing Tax Credit Program: At December 31, 1998, the company had invested approximately $65 million to purchase AHTC investments in limited partnerships. The company is committed to investing approximately $25 million more in AHTC investments by April 1, 2001. Manufactured Gas Sites: The company has been associated with 15 former manufactured gas sites located in Kansas 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 the 15 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 analysis. At December 31, 1998, the costs incurred for preliminary site investigation and risk assessment have been minimal. In accordance with the terms of the strategic alliance with ONEOK, ownership of twelve of these sites and the responsibility for clean-up of these sites were transferred to ONEOK. The ONEOK agreement limits the company's future liability associated with these sites to an immaterial amount. The company's investment earnings from ONEOK could be impacted by these costs. 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 Wolf Creek'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. 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 by the NRC. The company's share of any remaining proceeds can be used for property damage. 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. 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 and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 1998, Wolf Creek'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 $2.3 billion. 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 commitments in 1998 dollars under the remaining terms of the contracts was approximately $30.3 million. The natural gas transportation contracts provide firm service to the company's gas burning facilities expiring at various times through 2010. 11. INTERNATIONAL POWER DEVELOPMENT ACTIVITIES During the fourth quarter of 1998, management decided to exit the international power development business. This business had been conducted by the company's wholly owned subsidiary, The Wing Group (Wing). The company acquired Wing in February 1996 in an acquisition accounted for as a purchase. Wing's principal office was located near Houston, Texas and power development activities were primarily conducted in emerging markets. The company has acquired a 50% interest in a joint venture which has a 49% interest in four 55 MW generating facilities in the People's Republic of China. The company also owns a 37.5% interest in a 160 MW merchant generating facility in Colombia, and a 9% interest in a 478 MW power generating facility in the Republic of Turkey. Unfavorable economic, political and regulatory developments in certain emerging markets where development efforts were focused required management to reexamine this business. In exiting this business, management has decided to discontinue existing development efforts and cease future development activity. The company had been spending approximately $10 million annually to fund development efforts. The company was required to record a charge to income as a result of exiting this business. The charge to earnings has been presented as a separate line item as a component of operating expenses in the accompanying Consolidated Statements of Income. The detailed components of this charge are as follows: (Dollars in Thousands) Write-down equity investments to fair market value . . . . . . . . . . . . . . . $57,030 Accrued exit fees, shut-down and severance costs. . . . . . . . . . . . . . 22,900 Deferred development costs associated with projects to be abandoned. . . . . . . 6,735 Unamortized goodwill associated with the acquisition of Wing. . . . . . . . . . . . 12,251 Total charge. . . . . . . . . . . . . . $98,916 Overall negative economic, competitive and political factors, together with currently anticipated cash flows, have reduced the value of certain equity investments presently held. The decline in value of these investments required management to write down the investments to fair market value. Management considers this decline in value to be other than temporary. In assessing the value, management talked to others with investment experience in emerging markets and applied a discounted cash flow analysis to estimate fair market value. In accordance with the exit plan, the company will discontinue all development activity on February 1, 1999 and close all Wing offices. The employees of Wing were notified prior to December 31, 1998, of their termination effective February 1, 1999. Severance costs have been accrued for the approximately 30 affected employees. The company's exit plan calls for all significant aspects of the closure to be completed during 1999. 12. UNCONSOLIDATED SUBSIDIARIES The company's investments in unconsolidated subsidiaries which are accounted for by the equity method are as follows:

The following summarized financial information for the company's investment in ONEOK is presented as of and for the period ended November 30, 1998 and 1997, the most recent period for which public information is available. November 30, 1998 1997 (Dollars in Thousands) Balance Sheet: Current assets . . . . . $ 404,358 $ 532,681 Non-current assets . . . 2,091,797 1,761,561 Current liabilities. . . 338,466 443,080 Non-current liabilities. 993,668 729,920 Equity . . . . . . . . . 1,164,021 1,121,242 Year Ended November 30, 1998 1997 (Dollars in Thousands) Income Statement: Revenues . . . . . . . . $1,908,713 $1,227,335 Operating expenses . . . 1,767,286 1,134,024 Net income . . . . . . . 103,525 59,614 13. EMPLOYEE BENEFIT PLANS Pension: The company maintains qualified noncontributory defined benefit pension plans covering substantially all utility employees. Pension benefits are based on years of service and the employee's compensation during the five highest paid consecutive years out of ten before retirement. The company's policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. The company also maintains a non-qualified Executive Salary Continuation Program for the benefit of certain management employees, including executive officers. Postretirement Benefits: The company accrues the cost of postretirement benefits, primarily medical benefit costs, during the years an employee provides service. The following tables summarize the status of the company's pension and other postretirement benefit plans:

For measurement purposes, an annual health care cost growth rate of 8% was assumed for 1998, decreasing 1% per year to 5% in 2001 and thereafter. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate by 1% each year would increase the present value of the accumulated projected benefit obligation by $2.1 million and the aggregate of the service and interest cost components by $0.2 million. In accordance with an order from the KCC, the company has deferred postretirement and postemployment expenses in excess of actual costs paid. In 1997, the company received authorization from the KCC to invest in AHTC investments. Income from the AHTC investments will be used to offset the deferred and incremental costs associated with postretirement and postemployment benefits offered to the company's employees. The income generated from the AHTC investments replaces the income stream from corporate-owned life insurance contracts purchased in 1993 and 1992 which was used for the same purpose. Savings: The company maintains savings plans in which substantially all employees participate, with the exception of Protection One employees. The company matches employees' contributions up to specified maximum limits. The funds of the plans are deposited with a trustee and invested at each employee's option in one or more investment funds, including a company stock fund. The company's contributions were $3.8 million, $5.0 million and $4.6 million for 1998, 1997 and 1996, respectively. Protection One also maintains a savings plan. Contributions, made at Protection One's election, are allocated among participants based upon the respective contributions made by the participants through salary reductions during the year. Protection One's matching contributions may be made in Protection One common stock, in cash or in a combination of both stock and cash. Protection One's matching contribution to the plan for 1998 and 1997 was $992,000 and $34,000, respectively. Protection One maintains a qualified employee stock purchase plan that allows eligible employees to acquire shares of Protection One common shares at 85% of fair market value of the common stock. A total of 650,000 shares of common stock have been reserved for issuance in this program. Stock Based Compensation Plans: The company, excluding Protection One, has a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan. The LTISA Plan was implemented to help ensure that key employees and board members (Plan Participants) were properly incented to increase shareholder value. Under the LTISA Plan, the company may grant awards in the form of stock options, dividend equivalents, share appreciation rights, restricted shares, restricted share units, performance shares and performance share units to Plan Participants. Up to three million shares of common stock may be granted under the LTISA Plan. Stock options and restricted shares under the LTISA plan are as follows:

Stock options and restricted shares issued and outstanding at December 31, 1998, are as follows:

An equal amount of dividend equivalents is issued to recipients of stock options. The weighted-average grant-date fair value of the dividend equivalent was $6.88 and $6.21 in 1998 and 1997, respectively. The value of each dividend equivalent is calculated as a percentage of the accumulated dividends that would have been paid or payable on a share of company common stock. This percentage ranges from zero to 100%, based upon certain company performance factors. The dividend equivalents expire after nine years from date of grant. The fair value of stock options and dividend equivalents were estimated on the date of grant using the Black-Scholes option-pricing model. The model assumed the following at December 31: 1998 1997 Dividend yield. . . . . . . . . . 6.16% 6.58% Expected stock price volatility . 17.82% 13.56% Risk-free interest rate: Stock options . . . . . . . . . 4.87% 6.72% Dividend equivalents (1). . . . 4.63% 6.36% (1) Assuming an award percentage of 100% and dividend accumulation period of five years. Protection One Stock Warrants and Options: Protection One has outstanding stock warrants and options which were considered reissued and exercisable upon the company's acquisition of Protection One on November 24, 1997. The 1997 Long-Term Incentive Plan (the LTIP), approved by the Protection One stockholders on November 24, 1997, provides for the award of incentive stock options to directors, officers and key employees. Under the LTIP, 4.2 million shares are reserved for issuance subject to such adjustment as may be necessary to reflect changes in the number or kinds of shares of common stock or other securities of Protection One. The LTIP provides for the granting of options that qualify as incentive stock options under the Internal Revenue Code and options that do not so qualify. During 1998, Protection One granted options under the LTIP to purchase an aggregate of 1,246,500 shares of common stock to employees, including 690,000 shares granted to officers of Protection One. Each option has a term of 10 years and vests 100% on the third anniversary of the option grant. The purchase price of the shares issuable pursuant to the options is equal to (or greater than) the fair market value of the common stock at the date of the option grant. A summary of warrant and option activity for Protection One from the date of the acquisition transaction is as follows: December 31, 1998 1997 Weighted- Weighted- Average Average Exercise Exercise Shares Price Shares Price Outstanding, beginning of year(1) 2,366,435 $ 5.805 2,366,741 $5.805 Granted . . . . . . . . . . . . . 1,246,500 11.033 - - Exercised (109,595) 5.564 (306) 0.050 Forfeited . . . . . . . . . . . . (117,438) 10.770 - - Adjustment to May 1995 warrants . 36,837 - - - Outstanding, end of year. . . . . 3,422,739 $ 7.494 2,366,435 $5.805 (1) There was no outstanding stock or options prior to November 24, 1997. Stock options and warrants issued and outstanding at December 31, 1998, are as follows: Number Weighted- Weighted- Range of Issued Average Average Exercise and Remaining Life Exercise Price Outstanding (Years) Price Exercisable: $ 6.375-$ 9.125 136,560 6 $ 6.588 8.000- 10.313 349,000 7 8.062 13.750- 15.500 142,000 7 14.883 9.500 217,000 8 9.500 15.000 50,000 8 15.000 14.268 50,000 3 14.268 3.633 103,697 2 3.633 0.167 428,400 5 0.167 3.890 786,277 6 3.890 0.050 305 8 0.050 2,263,239 Not Exercisable: $11.033 1,120,500 9 $11.033 9.500- 12.500 39,000 9 11.942 1,159,500 Total outstanding 3,422,739 The company holds a call option for an additional 2,750,238 shares of Protection One common stock, exercisable at a call price of $15.50 per share. The option expires on the earlier of (i) 45 days following the last date on which any Protection One convertible notes are still outstanding or (ii) October 31, 1999. The weighted average fair value of options granted during 1998 and estimated on the date of grant was $6.87. The fair value was calculated using the following assumptions: Year ended December 31, 1998 Dividend yield. . . . . . . . . 0.00% Expected stock price volatility 61.72% Risk free interest rate . . . . 5.50% Expected option life. . . . . . 6 years The company accounts for both the company's and Protection One's plans under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and the related interpretations. Had compensation expense been determined pursuant to Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," the company would have recognized additional compensation costs during 1998, 1997 and 1996 as shown in the table below. Year Ended December 31, 1998 1997 1996 (Dollars in Thousands, Except Per Share Amounts) Earnings available for common stock: As reported . . . . . . . . . . $44,165 $494,599 $154,111 Pro forma . . . . . . . . . . . 42,640 494,436 153,877 Earnings per common share (basic and diluted): As reported . . . . . . . . . . $0.67 $7.59 $2.41 Pro forma . . . . . . . . . . . 0.65 7.59 2.41 Split Dollar Life Insurance Program: The company has established a split dollar life insurance program for the benefit of the company and certain of its executives. Under the program, the company has purchased a life insurance policy on the executive's life, and, upon the executive's death, the executive's beneficiary is entitled to a death benefit in an amount equal to the face amount of the policy reduced by the greater of (i) all premiums paid by the company or (ii) the cash surrender value of the policy, which amount, at the death of the executive, will be returned to the company. The company retains an equity interest in the death benefit and cash surrender value of the policy to secure this repayment obligation. Subject to the conditions described below, beginning on the earlier of (i) three years from the date of the policy or (ii) the first day of the next calendar year following the date of the executive's retirement, the executive is allowed to transfer to the company from time to time, in whole or in part, his interest in the death benefit under the policy at a discount equal to $1 for each $1.50 of the portion of the death benefit for which the executive officer may designate the beneficiary, subject to adjustment based on the total return to shareholders from the date of the policy unless the participant retires from the company within six months of the date of the participant's agreement. Any adjustment would result in an exchange of no more than one dollar for each dollar of death benefit nor less than one dollar for each two dollars of death benefit. The program has been designed such that upon the executive's death the company will recover its premium payments from the policy and any amounts paid by the company to the executive for the transfer of his interest in the death benefit. The cash surrender value of these policies has been recorded in other assets. The insurance premium and the estimated value of the executives' agreements have been expensed. The company has accrued approximately $57 million at December 31, 1998 for this program. Under current tax rules, payments to certain participants in exchange for their interest in the death benefits may not be fully deductible by the company for income tax purposes. 14. 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, redeemable preference stock and other mandatorily redeemable securities 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 estimated fair values of contracts related to commodities have been determined using quoted market prices of the same or similar securities. The recorded amounts 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 a substantial portion of the company's operations are regulated, the company believes that any gains or losses related to the retirement of debt or redemption of preferred securities would not have a material effect on the company's financial position or results of operations. 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, net of current maturities . . 2,956,692 2,019,103 3,076,709 2,101,167 Redeemable preference stock. . . . . . . . . - 50,000 - 51,750 Other mandatorily redeemable securities. 220,000 220,000 226,800 226,088 In its commodity price risk management activities, the company engages in both trading and non-trading activities. In these activities, the company utilizes a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps which require payments (or receipt of payments) from counterparties based on the differential between specified prices for the related commodity, and futures traded on electricity and natural gas. For a discussion of the accounting policy for these instruments, see Note 1. The company is involved in trading activities primarily to minimize risk from market fluctuations, maintain a market presence and to enhance system reliability. Although the company attempts to balance its physical and financial purchase and sale contracts in terms of quantities and contract terms, net open positions can exist or are established due to the origination of new transactions and the company's assessment of, and response to, changing market conditions. The company uses derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of cash market prices. December 31, 1998 1997 (Dollars in Thousands) Notional Notional Volumes Estimated Volumes Estimated (MWH's) Fair Value (MWH's) Fair Value Forward contracts: Purchased. . . . 1,535,600 $46,361 359,200 $8,604 Sold . . . . . . 1,535,600 46,141 359,200 8,806 Options: Purchased. . . . 148,800 $ 361 803,200 $1,607 Sold . . . . . . 64,000 195 120,800 512 Forward contracts and options had a net unrealized gain of $40,000 at December 31, 1998, and a net unrealized loss of $127,000 at December 31, 1997. 15. GAIN ON SALE OF EQUITY SECURITIES During 1996, the company acquired 27% of the common shares of ADT Limited, Inc. (ADT) and made an offer to acquire the remaining ADT common shares. ADT rejected this offer and in July 1997, ADT merged with Tyco International Ltd. (Tyco). ADT and Tyco completed their merger by exchanging ADT common stock for Tyco common stock. Following the ADT and Tyco merger, the company's equity investment in ADT became an available-for-sale security. During the third quarter of 1997, the company sold its Tyco common shares for approximately $1.5 billion. The company recorded a pre-tax gain of $864 million on the sale and recorded tax expense of approximately $345 million in connection with this gain. 16. INCOME TAXES Income tax expense is composed of the following components at December 31: 1998 1997 1996 (Dollars in Thousands) Currently payable: Federal. . . . . . . . . . . $ 52,993 $336,150 $54,644 State. . . . . . . . . . . . 10,881 72,143 20,280 Deferred: Federal. . . . . . . . . . . (39,067) (15,945) 14,808 State. . . . . . . . . . . . (4,185) (2,696) (615) Amortization of investment tax credits . . . . . . . . . (6,065) (6,665) (6,758) Total income tax expense . . . $ 14,557 $382,987 $82,359 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 Monitored services deferred tax assets. . . . 132,802 98,712 Other. . . . . . . . . . . . . . . . . . . . 138,506 94,008 Total deferred tax assets. . . . . . . . . $ 363,735 $ 290,354 Deferred tax liabilities: Accelerated depreciation and other . . . . . $ 615,492 $ 625,176 Acquisition premium. . . . . . . . . . . . . 291,156 299,162 Deferred future income taxes . . . . . . . . 206,114 213,658 Other. . . . . . . . . . . . . . . . . . . . 85,987 112,555 Total deferred tax liabilities . . . . . . $1,198,749 $1,250,551 Investment tax credits . . . . . . . . . . . . $ 103,645 $ 109,710 Accumulated deferred income taxes, net . . . . $ 938,659 $1,069,907 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 also are a temporary difference for which deferred income tax liabilities have been provided. 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 Effective income tax rate. . . . . . . . . 24.0% 43.4% 32.8% Effect of: State income taxes. . . . . . . . . . . . (4.5) (5.0) (5.1) Amortization of investment tax credits. . 10.0 0.8 2.7 Corporate-owned life insurance policies . 15.0 0.9 3.7 Accelerated depreciation flow through and amortization, net . . . . . . . . . (2.9) (0.4) (0.2) Adjustment to tax provision . . . . . . . (11.3) (3.7) - Dividends received deduction. . . . . . . 16.0 - - Amortization of goodwill. . . . . . . . . (11.4) - - Other . . . . . . . . . . . . . . . . . . 0.1 (1.0) 1.1 Statutory federal income tax rate. . . . . 35.0% 35.0% 35.0% 17. 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. . . . . . . $5,646,176 $5,564,695 Less - accumulated depreciation. . . . 2,015,880 1,895,084 3,630,296 3,669,611 Construction work in progress. . . . . 77,927 60,006 Nuclear fuel (net) . . . . . . . . . . 39,497 40,696 Net utility plant. . . . . . . . . . 3,747,720 3,770,313 Non-utility plant in service . . . . . 62,324 20,237 Less - accumulated depreciation. . . . 14,901 4,022 Net property, plant and equipment. . $3,795,143 $3,786,528 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. 18. LEASES At December 31, 1998, the company had leases covering various property and equipment. The company currently has no significant capital leases. Rental payments for operating leases and estimated rental commitments are as follows: Operating Year Ended December 31, Leases (Dollars in Thousands) 1996 . . . . . . . . . . . . . . $ 63,181 1997 . . . . . . . . . . . . . . 71,126 1998 . . . . . . . . . . . . . . 70,796 Future Commitments: 1999 . . . . . . . . . . . . . . 64,355 2000 . . . . . . . . . . . . . . 58,573 2001 . . . . . . . . . . . . . . 55,073 2002 . . . . . . . . . . . . . . 55,293 2003 . . . . . . . . . . . . . . 57,530 Thereafter . . . . . . . . . . . 650,893 Total. . . . . . . . . . . . . . $941,717 In 1987, KGE 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. KGE 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. The company recognized a gain on the sale which was deferred and is being amortized over the initial lease term. In 1992, the company deferred costs associated with the refinancing of the secured facility bonds of the Trustee and owner of La Cygne 2. These costs are being amortized over the life of the lease and are included in operating expense. Approximately $20.3 million of this deferral remained on the Consolidated Balance Sheet at December 31, 1998. Future minimum annual lease payments, included in the table above, 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. KGE'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. 19. 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. Management has segmented its business based on differences in products and services, production processes, and management responsibility. Based on this approach, the company has identified four reportable segments: fossil generation, nuclear generation, power delivery and monitored services. Fossil generation, nuclear generation and power delivery represent the three business segments that comprise the company's regulated electric utility business in Kansas. Fossil generation produces power for sale to external wholesale customers outside the company's historical marketing territory and internally to the power delivery segment. Power marketing is a component of the company's fossil generation segment which attempts to minimize market fluctuation risk, enhance system reliability and maintain a market presence. Nuclear generation represents the company's 47% ownership in the Wolf Creek nuclear generating facility. This segment does not have any external sales. The power delivery segment consists of the transmission and distribution of power to approximately 620,000 wholesale and retail customers in Kansas. The company's monitored services business was expanded in November 1997 with the acquisition of a majority interest in Protection One. Protection One provides monitored services to approximately 1.5 million customers in North America, the United Kingdom, and Continental Europe. Other represents the company's non-utility operations and natural gas business. 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. Unusual items, such as charges to income, may be excluded from segment performance depending on the nature of the charge or income. The company's ONEOK investment, marketable securities investments and other equity method investments do not represent operating segments of the company. The company has no single external customer from which it receives ten percent or more of its revenues.

Geographic Information: Prior to 1998, the company did not have international sales or international property, plant and equipment. The company's sales and property, plant and equipment as of and for the period ending December 31, 1998 are as follows: North America International Operations Operations Total (Dollars in Thousands) External sales . . . . . $1,990,329 $43,725 $2,034,054 Property, plant and equipment, net . . . . 3,787,872 7,271 3,795,143 2O. 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 297,020 134,054 617 84 Jeffrey 2 (b) May 1980 292,555 128,210 622 84 Jeffrey 3 (b) May 1983 405,054 160,671 621 84 Wolf Creek (c) Sep 1985 1,377,348 429,934 547 47 (a) Jointly owned with KCPL (b) Jointly owned with UtiliCorp United Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc. Amounts and capacity presented above 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 Consolidated Statements of Income. The company's share of other transactions associated with the plants is included in the appropriate classification in the company's consolidated financial statements. 21. MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY On February 7, 1997, the company signed a merger agreement with Kansas City Power & Light Company (KCPL) by which KCPL would be merged with and into the company in exchange for company stock. In December 1997, representatives of the company's 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, the company and KCPL agreed to a restructuring of their February 7, 1997, merger agreement which will result in the formation of Westar Energy, a new regulated electric utility company. Under the terms of the merger agreement, the electric utility operations of the company will be transferred to KGE, and KCPL and KGE will be merged into NKC, Inc., a subsidiary of the company. NKC, Inc. will be renamed Westar Energy. In addition, under the terms of the merger agreement, KCPL shareholders will receive company common stock which is subject to a collar mechanism of not less than .449 nor greater than .722, provided the amount of company 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 company 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, the company 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 the company, KCPL and KGE. Westar Energy will assume $2.7 billion in debt, consisting of $1.9 billion of indebtedness for borrowed money of the company and KGE, and $800 million from KCPL. Long-term debt of the company, excluding Protection One, 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 the company will be released from its obligations with respect to the company's debt to be assumed by Westar Energy. Pursuant to the merger agreement, the company has agreed, among other things, to redeem all outstanding shares of its 4 1/2% Series Preferred Stock, par value $100 per share, 4 1/4% Series Preferred Stock, par value $100 per share, and 5% Series Preferred Stock, par value $100 per share. Consummation of the merger is subject to customary conditions. On July 30, 1998, the company's shareholders and the shareholders of KCPL voted to approve the amended merger agreement at special meetings of shareholders. The company 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 we believe would make the merger uneconomical. The merger agreement allows the company to terminate the agreement if regulatory approvals are not acceptable. 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. The company does not anticipate the proposed legislation to pass in its current form. The company 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, the company 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. The company 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. The company, KCPL and KGE have joint interests in certain electric generating assets, including Wolf Creek. At December 31, 1998, the company 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 Kansas City Power & Light Company, see the company's Registration Statement on Form S-4 filed on June 9, 1998. 22. QUARTERLY RESULTS (UNAUDITED) The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. The electric 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. First Second Third Fourth (Dollars in Thousands, Except Per Share Amounts) 1998 (Restated) Sales . . . . . . . . . . . . . $382,343 $463,301 $701,402 $487,008 Income from operations(1) . . . 64,795 72,314 156,307 (62,902) Net income(1) . . . . . . . . . 29,813 31,006 71,422 (84,485) Earnings applicable to common stock. . . . . . . . . 28,583 29,209 71,140 (84,767) Basic earnings per share. . . . $ 0.44 $ 0.45 $ 1.08 $ (1.29) Dividends per share . . . . . . $ 0.535 $ 0.535 $ 0.535 $ 0.535 Average common shares outstanding . . . . . . . . . 65,410 65,543 65,707 65,870 Common stock price: High. . . . . . . . . . . . . $ 44.188 $ 42.688 $ 41.625 $ 43.250 Low . . . . . . . . . . . . . $ 40.000 $ 36.875 $ 37.688 $ 32.563 1997 (Restated) Sales . . . . . . . . . . . . . $626,198 $454,006 $559,996 $511,565 Income from operations(2) . . . 103,297 57,498 110,391 (116,761) Net income(2),(3) . . . . . . . 41,033 24,335 508,372 (74,222) Earnings applicable to common stock. . . . . . . . . 39,803 23,106 507,142 (75,452) Basic earnings per share. . . . $ 0.61 $ 0.36 $ 7.77 $ (1.15) Dividends per share . . . . . . $ 0.525 $ 0.525 $ 0.525 $ 0.525 Average common shares outstanding . . . . . . . . . 64,807 65,045 65,243 65,408 Common stock price: High. . . . . . . . . . . . . $ 31.50 $ 32.75 $ 35.00 $ 43.438 Low . . . . . . . . . . . . . $ 30.00 $ 29.75 $ 32.25 $ 33.625 (1) The loss in the fourth quarter of 1998, is primarily attributable to a $99 million charge to income to exit the company's international power development business. (2) During the fourth quarter of 1997, the company expensed deferred costs of approximately $48 million associated with the original KCPL merger agreement. Protection One recorded a charge to income of approximately $24 million. (3) During the third quarter of 1997, the company recorded a pre-tax gain of approximately $864 million upon selling its Tyco common stock. The summarized information for the fourth quarter of 1997 and for each quarter in 1998 have been revised to reflect a restatement at Protection One. The restatement expenses yard signs previously capitalized and includes the impact of reversing the accrual for the signage charge previously recorded at December 31, 1997 (see Note 2). The impact of the adjustments made to the company's previously reported quarterly results in 1998, net of tax and net of the minority interest is as follows: (Dollars in Thousands) Expense yard signs as incurred $ 8,312 Increase bad debt provision 3,090 Other (554) Decrease in net income $10,848 The impact of these adjustments on the quarterly results previously reported is as follows. (Amounts are net of tax and net of minority interest): Net Income (dollars in thousands) Earnings Per Share Increase (Decrease) Increase (Decrease) 1998 - First Quarter $ (655) $(0.01) Second Quarter (3,813) (0.05) Third Quarter (1,343) (0.02) Fourth Quarter (5,037) (0.08) 1997 - Fourth Quarter $ 5,424 $0.08 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information relating to the company's Directors required by Item 10 is set forth in the company's definitive proxy statement for its 1999 Annual Meeting of Shareholders to be filed with the SEC. Such information is incorporated herein by reference to the material appearing under the caption Election of Directors in the proxy statement to be filed by the company with the SEC. See EXECUTIVE OFFICERS OF THE COMPANY in the proxy statement for the information relating to the company's Executive Officers as required by Item 10. ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is set forth in the company's definitive proxy statement for its 1999 Annual Meeting of Shareholders to be filed with the SEC. Such information is incorporated herein by reference to the material appearing under the captions Information Concerning the Board of Directors, Executive Compensation, Compensation Plans, and Human Resources Committee Report in the proxy statement to be filed by the company with the SEC. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 is set forth in the company's definitive proxy statement for its 1999 Annual Meeting of Shareholders to be filed with the SEC. Such information is incorporated herein by reference to the material appearing under the caption Beneficial Ownership of Voting Securities in the proxy statement to be filed by the company with the SEC. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K The following financial statements are included herein. FINANCIAL STATEMENTS Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 1998 and 1997 Consolidated Statements of Income, for the years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Comprehensive Income, for the years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Cash Flows, for the years ended December 31, 1998, 1997 and 1996 Consolidated Statements of Cumulative Preferred and Preference Stock, December 31, 1998 and 1997 Consolidated Statements of Shareholders' Equity, for the years ended December 31, 1998, 1997 and 1996 Notes to Consolidated Financial Statements SCHEDULES Schedule II - Valuation and Qualifying Accounts Schedules omitted as not applicable or not required under the Rules of regulation S-X: I, III, IV, and V REPORTS ON FORM 8-K Form 8-K filed January 5, 1998 - Press release regarding merger with Kansas City Power and Light Company. Form 8-K filed March 23, 1998 - Amended and Restated Agreement and Plan of Merger between the company and KCPL, dated as of March 18, 1998. Form 8-K filed July 13, 1998 - Kansas City Power and Light Company December 31, 1997 Form 10-K and March 31, 1998 Form 10-Q. Form 8-K filed August 3, 1998 - Computations of Ratio of Earnings to Fixed Charges and Computations of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements, press release reporting second quarter earnings issued July 30, 1998, and press release announcing approval by shareholders of KCPL merger agreement issued July 30, 1998. Form 8-K filed August 6, 1998 - Kansas City Power and Light Company June 30, 1998 Form 10-Q. Form 8-K filed January 28, 1999 - Press release regarding annual earnings and dividends declared. Form 8-K filed April 1, 1999 - Press release reporting Western Resources extends filing period for 10-K. EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. Description 3(a) -Amended and Restated Agreement and Plan of Merger between I the company and KCPL, dated as of March 18, 1998. (filed as Exhibit 99.2 to the March 23, 1998 Form 8-K) 3(b) -By-laws of the company, as amended March 19, 1997. (filed as Exhibit 3 to the March 31, 1997 Form 10-Q) I 3(c) -Agreement and Plan of Merger between the company and KCPL, I dated as of February 7, 1997. (filed as Exhibit 99.2 to the February 10, 1997 Form 8-K) 3(d) -Agreement between the company and ONEOK dated as of I December 12, 1996. (filed as Exhibit 99.2 to the December 12, 1997 Form 8-K) 3(e) -Form of Shareholder Agreement between New ONEOK and the I company. (filed as Exhibit 99.3 to the December 12, 1997 Form 8-K) 3(f) -Restated Articles of Incorporation of the company, as amended I through May 25, 1988, filed as Exhibit 4 to Registration Statement, SEC File No. 33-23022 (incorporated by reference). 3(g) -Certificate of Amendment to Restated Articles of Incorporation I of the company dated March 29, 1991. 3(h) -Certificate of Designations for Preference Stock, 8.5% Series, I without par value, dated March 31, 1991 and filed as exhibit 3(d) to December 1993 Form 10-K (incorporated by reference). 3(i) -Certificate of Correction to Restated Articles of Incorporation I of the company dated December 20, 1991, filed as exhibit 3(b) to December 1991 Form 10-K (incorporated by reference). 3(j) -Certificate of Designations for Preference Stock, 7.58% Series, I without par value, dated April 8, 1992 and filed as exhibit 3(e) to December 1993 form 10-K (incorporated by reference). 3(k) -Certificate of Amendment to Restated Articles of Incorporation of I the company dated May 8, 1992, filed as exhibit 3(c) to December 31, 1994 Form 10-K (incorporated by reference). 3(l) -Certificate of Amendment to Restated Articles of Incorporation I of the company dated May 26, 1994, filed as exhibit 3 to June 1994 Form 10-Q (incorporated by reference). 3(m) -Certificate of Amendment to Restated Articles of Incorporation I of the company dated May 14, 1996, filed as exhibit 3(a) to June 1996 Form 10-Q (incorporated by reference). 3(n) -Certificate of Amendment to Restated Articles of Incorporation I of the company dated May 12, 1998, filed as exhibit 3 to March 1998 Form 10-Q (incorporated by reference). 4(a) -Deferrable Interest Subordinated Debentures dated November 29, I 1995, between the company and Wilmington Trust Delaware, Trustee (filed as Exhibit 4(c) to Registration Statement No. 33-63505) 4(b) -Mortgage and Deed of Trust dated July 1, 1939 between the Company I and Harris Trust and Savings Bank, Trustee. (filed as Exhibit 4(a) to Registration Statement No. 33-21739) 4(c) -First through Fifteenth Supplemental Indentures dated July 1, I 1939, April 1, 1949, July 20, 1949, October 1, 1949, December 1, 1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954, September 1, 1961, April 1, 1969, September 1, 1970, February 1, 1975, May 1, 1976 and April 1, 1977, respectively. (filed as Exhibit 4(b) to Registration Statement No. 33-21739) 4(d) -Sixteenth Supplemental Indenture dated June 1, 1977. (filed as I Exhibit 2-D to Registration Statement No. 2-60207) 4(e) -Seventeenth Supplemental Indenture dated February 1, 1978. I (filed as Exhibit 2-E to Registration Statement No. 2-61310) 4(f) -Eighteenth Supplemental Indenture dated January 1, 1979. (filed I as Exhibit (b) (1)-9 to Registration Statement No. 2-64231) 4(g) -Nineteenth Supplemental Indenture dated May 1, 1980. (filed as I Exhibit 4(f) to Registration Statement No. 33-21739) 4(h) -Twentieth Supplemental Indenture dated November 1, 1981. (filed I as Exhibit 4(g) to Registration Statement No. 33-21739) 4(i) -Twenty-First Supplemental Indenture dated April 1, 1982. (filed I as Exhibit 4(h) to Registration Statement No. 33-21739) 4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983. I (filed as Exhibit 4(i) to Registration Statement No. 33-21739) 4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986. I (filed as Exhibit 4(j) to Registration Statement No. 33-12054) 4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987. I (filed as Exhibit 4(k) to Registration Statement No. 33-21739) 4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988. I (filed as Exhibit 4 to the September 1988 Form 10-Q) 4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990. I (filed as Exhibit 4(m) to the December 1989 Form 10-K) 4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992. I (filed as exhibit 4(n) to the December 1991 Form 10-K) 4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992. I (filed as exhibit 4(o) to the December 1992 Form 10-K) 4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992. I (filed as exhibit 4(p) to the December 1992 Form 10-K) 4(r) -Thirtieth Supplemental Indenture dated February 1, 1993. I (filed as exhibit 4(q) to the December 1992 Form 10-K) 4(s) -Thirty-First Supplemental Indenture dated April 15, 1993. I (filed as exhibit 4(r) to Registration Statement No. 33-50069) 4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994, I (filed as Exhibit 4(s) to the December 31, 1994 Form 10-K) 4(u) -Debt Securities Indenture dated August 1, 1998 , I (filed as Exhibit 4.1 to the September 1998 Form 10-Q) 4(v) -Form of Note for $400 million 6.25% Putable/Callable Notes due I August 15, 2018, Putable/Callable August 15, 2003 (filed as Exhibit 4.2 to the September 1998 Form 10-Q) 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) -Long-term Incentive and Share Award Plan (filed as Exhibit I 10(a) to the June 1996 Form 10-Q) 10(b) -Form of Employment Agreement with officers of the Company I (filed as Exhibit 10(b) to the June 1996 Form 10-Q) 10(c) -A Rail Transportation Agreement among Burlington Northern I Railroad Company, the Union Pacific Railroad Company and the Company (filed as Exhibit 10 to the June 1994 Form 10-Q) 10(d) -Agreement between the Company and AMAX Coal West Inc. I effective March 31, 1993. (filed as Exhibit 10(a) to the December 31, 1993 Form 10-K) 10(e) -Agreement between the Company and Williams Natural Gas Company I dated October 1, 1993. (filed as Exhibit 10(b) to the December 31, 1993 Form 10-K) 10(f) -Letter of Agreement between The Kansas Power and Light Company I and John E. Hayes, Jr., dated November 20, 1989. (filed as Exhibit 10(w) to the December 31, 1989 Form 10-K) 10(g) -Amended Agreement and Plan of Merger by and among The Kansas I Power and Light Company, KCA Corporation, and Kansas Gas and Electric Company, dated as of October 28, 1990, as amended by Amendment No. 1 thereto, dated as of January 18, 1991. (filed as Annex A to Registration Statement No. 33-38967) 10(h) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I December 31, 1993 Form 10-K) 10(i) -Long-term Incentive Plan (filed as Exhibit 10(j) to the I December 31, 1993 Form 10-K) 10(j) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I December 31, 1993 Form 10-K) 10(k) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I 10(l) to the December 31, 1993 Form 10-K) 10(l) -Executive Salary Continuation Plan of Western Resources, Inc., I as revised, effective September 22, 1995. (filed as Exhibit 10(j)to the December 31, 1995 Form 10-K) 10(m) -Executive Salary Continuation Plan for John E. Hayes, Jr., I Dated March 15, 1995. (filed as Exhibit 10(k) to the December 31, 1995 Form 10-K) 10(n) -Stock Purchase Agreement between the company and Laidlaw I Transportation Inc., dated December 21, 1995. (filed as Exhibit 10(l) to the December 31, 1995 Form 10-K) 10(o) -Equity Agreement between the company and Laidlaw Transportation I Inc., dated December 21, 1995. (filed as Exhibit 10(l)1 to the December 31, 1995 Form 10-K) 10(p) -Letter Agreement between the company and David C. Wittig, I dated April 27, 1995. (filed as Exhibit 10(m) to the December 31, 1995 Form 10-K) 10(q) -Transaction Confirmation for $400 million 6.25% Putable/Callable I Notes due August 15, 2018, Putable/Callable August 15, 2003. (filed as Exhibit 10.1 to the September 30, 1998 Form 10-Q) 10(r) -Amendment to Letter Agreement between the company and David C. I Wittig, dated April 27, 1995 (filed as Exhibit 10.2 to the September 30, 1998 Form 10-Q) 10(q) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 I to the September 30, 1998 Form 10-Q) 12 -Computation of Ratio of Consolidated Earnings to Fixed Charges. (filed electronically) 21 -Subsidiaries of the Registrant. (filed electronically) 23 -Consent of Independent Public Accountants, Arthur Andersen LLP (filed electronically) 27 -Financial Data Schedule (filed electronically) WESTERN RESOURCES, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands)

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. WESTERN RESOURCES, INC. April 14, 1999 By /s/ DAVID C. WITTIG David C. Wittig, Chairman of the Board, President and Chief Executive Officer 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 Chairman of the Board, /s/ DAVID C. WITTIG President and Chief Executive April 14, 1999 (David C. Wittig) Officer (Principal Executive Officer) Acting Executive Vice President /s/ WILLIAM B. MOORE and Chief Financial Officer April 14, 1999 (William B. Moore) (Principal Financial and Accounting Officer) /s/ FRANK J. BECKER (Frank J. Becker) /s/ C. Q. CHANDLER (C. Q. Chandler) /s/ THOMAS R. CLEVENGER (Thomas R. Clevenger) /s/ JOHN C. DICUS Directors April 14, 1999 (John C. Dicus) /s/ DAVID H. HUGHES (David H. Hughes) /s/ RUSSELL W. MEYER, JR. (Russell W. Meyer, Jr.) /s/ JANE DESNER SADAKA (Jane Desner Sadaka) /s/ LOUIS W. SMITH (Louis W. Smith)

Exhibit 3 CERTIFICATE OF AMENDMENT TO RESTATED ARTICLES OF INCORPORATION, AS AMENDED, OF THE KANSAS POWER AND LIGHT COMPANY We, John E. Hayes, Jr., Chairman of the Board, President and Chief Executive Officer and John K. Rosenberg, Secretary of the above named corporation, a corporation organized and existing under the laws of the State of Kansas, do hereby certify that at a meeting of the Board of Directors of said corporation, the board adopted a resolution setting forth the following amendment to the Restated Articles of Incorporation and declaring their advisability: FURTHER RESOLVED, That the following amendment of Article IV of the Company's Restated Articles of Incorporation be, and it hereby is proposed and declared advisable: The first paragraph of said Article VI to be amended and read as follows: The amount of capital stock of this Corporation shall be 95,600,000 shares of which 85,000,000 shares is Common Stock of the par value of Five Dollars ($5.00) each, 4,000,000 shares is Preference Stock without par value, 600,000 shares is preferred stock of the par value of One Hundred Dollars ($100) each and 6,000,000 shares is preferred stock without par value, all such preferred stock being termed "Preferred Stock"; and FURTHER RESOLVED, That the following amendment of Article XI of the Company's Restated Articles of Incorporation be, and it hereby is proposed and declared advisable: Article XI be amended and read as follows: The number of directors shall not be less than seven nor more than fifteen and the precise number shall be determined from time-to-time by the Board of Directors at any annual or special meeting within such minimum and maximum number, provided, that unless approved by a majority of the stockholders entitled to vote, the number of directors shall not be reduced to terminate the office of a director during the term for which he was elected. We further certify that thereafter, pursuant to said resolution, and in accordance with the by-laws of the corporation and the laws of the State of Kansas, the Board of Directors called a special meeting of shareholders for consideration of the proposed amendments, and thereafter, pursuant to notice and in accordance with the statutes of the State of Kansas, the shareholders convened and considered the proposed amendments. We further certify that at the meeting a majority of the shares of common stock entitled to vote and a majority of common and preferred shares together entitled to vote, voted in favor of the proposed amendments. We further certify that the amendments were duly adopted in accordance with the provisions of K.S.A. 17-6602, as amended. We further certify that the capital of said corporation will not be reduced under or by reason of said amendments. IN WITNESS WHEREOF, we have hereunto set our hands and affixed the seal of said corporation the 29th day of March, 1991. /s/John E. Hayes, Jr. John E. Hayes, Jr. Chairman of the Board, President and Chief Executive Officer /s/John K. Rosenberg John K. Rosenberg Secretary State of Kansas ) ) ss. County of Shawnee ) Be it remembered that before me, a Notary Public in and for the aforesaid county and state, personally appeared John E. Hayes, Jr., Chairman of the Board, President and Chief Executive Officer, and John K. Rosenberg, Secretary of the corporation named in this document, who are known to me to be the same persons who executed the foregoing certificate and duly acknowledge that execution of the same this 29th day of March, 1991 /s/Regina I. DeGarmo Notary Public [stamp of Notary Public]

Exhibit 12 WESTERN RESOURCES, INC. Computations of Ratio of Earnings to Fixed Charges and Computations of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements (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 previously filed Registration Statements File Nos. 333-59673, 33-49467, 33-49553, 333-02023, 33-50069, 333-26115, and 33-62375 of Western Resources, Inc. on Form S-3; Nos. 333-02711 and 333-56369 of Western Resources, Inc. on Form S-4; Nos. 333- 70891, 33-57435, 333-13229, 333-06887, 333-20393, 333-20413 and 333-75395 of Western Resources, Inc. on Form S-8; and No. 33-50075 of Kansas Gas and Electric Company on Form S-3. ARTHUR ANDERSEN LLP Kansas City, Missouri, April 13, 1999

Exhibit 21 WESTERN RESOURCES, INC. Subsidiaries of the Registrant State of Date Subsidiary Incorporation Incorporated 1) Kansas Gas and Electric Company Kansas October 9, 1990 2) Westar Capital, Inc. Kansas October 8, 1990 3) Protection One, Inc. Delaware June 21, 1991

5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE BALANCE SHEET AT DECEMBER 31, 1998 AND THE STATEMENT OF INCOME AND THE STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1000 YEAR DEC-31-1998 DEC-31-1998 16394 288077 252259 29544 95590 57225 5825925 2030782 7951428 1034846 3063064 220000 24858 329548 1608435 7951428 2034054 2034054 823259 1803540 0 0 226120 60722 14557 46165 0 1591 0 47756 0.67 0.67