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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------------------- FORM 10-K/A-2 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 ------------------------------------------------ For the fiscal year ended December 31, 2000 ----------------- [_] 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. () State the aggregate market value of the voting stock held by nonaffiliates of the registrant. Approximately $1,140,411,389 of Common Stock and $11,682,772 of Preferred Stock (excluding the 4 1/4% Series of Preferred Stock for which there is no readily ascertainable market value) at March 24, 2000. Indicate the number of shares outstanding of each of the registrant's classes of common stock. Common Stock, $5.00 par value 68,084,715 - ----------------------------- ------------------------------ (Class) (Outstanding at March 28, 2000) 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 15, 2000. 1
WESTERN RESOURCES, INC. TABLE OF CONTENTS Page ---- PART I Item 1. Business 4 Item 2. Properties 21 Item 3. Legal Proceedings 24 Item 4. Submission of Matters to a Vote of Security Holders 24 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 25 Item 6. Selected Financial Data 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 27 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 51 Item 8. Financial Statements and Supplementary Data 52 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 100 PART III Item 10. Directors and Executive Officers of the Registrant 100 Item 11. Executive Compensation 100 Item 12. Security Ownership of Certain Beneficial Owners and Management 100 Item 13. Certain Relationships and Related Transactions 100 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 101 Signatures 107 2
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, compliance with debt covenants, interest and dividends, the impact of Protection One's financial condition on our consolidated results, 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, accounting matters, and the overall economy of our service area. What happens in each case could vary materially from what we expect because of such things as electric utility deregulation, including ongoing municipal, state and federal activities; future economic conditions; legislative and regulatory developments; our regulatory and competitive markets; and other circumstances affecting anticipated operations, sales and costs. RESTATEMENT Following extensive conversations between Protection One and the Staff of the SEC, which have previously been disclosed, we have restated our Consolidated Financial Statements as of December 31, 1999, 1998 and 1997 and for the years then ended and for each of the periods ended March 31, June 30, and September 30, 2000, to reflect restatements undertaken by Protection One. This restatement primarily relates to the amortization of customer accounts acquired and amounts allocated to obligations assumed in the Westinghouse Security Systems (WSS) acquisition. A description of the principal adjustments which comprise the restatement for the three years ended December 31, 1999, 1998 and 1997 is disclosed in Note 2 of the Consolidated Financial Statements filed with this Form 10-K/A-2. A summary of the restated unaudited quarterly financial information for 1999, 1998, and 1997 is disclosed in Note 24 of the Consolidated Financial Statements. For the purpose of this Form 10-K/A-2, we have amended and restated in its entirety the 1999 Form 10-K filed on March 29, 2000. In order to preserve the nature and the character of the disclosures as of March 28, 2000, the date on which the original 1999 Form 10-K was signed, and as of April 3, 2000, the date on which the original Form 10-K/A for the year ended December 31, 1999, was signed, no attempt has been made in this Form 10-K/A-2 to modify or update such disclosures except as required to reflect the results of the restatement. 3
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 628,000 customers in Kansas and providing monitored services to approximately 1.6 million customers in North America, the United Kingdom and continental Europe. 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). 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. Our investments in Protection One and ONEOK are owned by Westar Capital, Inc. (Westar Capital), a wholly-owned subsidiary. The consolidated entities of Western Resources are referred to herein as "we." Our corporate headquarters are located at 818 Kansas Avenue, Topeka, Kansas 66612. On March 28, 2000, our board of directors approved the separation of our electric and non-electric utility businesses. The separation is currently expected to be effected through an exchange offer to be made to our shareholders in the third quarter of 2000. The exchange ratio will be described in materials furnished to shareholders upon commencement of the exchange offer. The impact on our financial position and operating results cannot be known until the exchange ratio is determined. We expect to complete the separation in the fourth quarter of 2000, but no assurance can be given that the separation will be completed. On March 18, 1998, we signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified us that it has terminated the contemplated transaction. We expensed costs related to the KCPL merger of approximately $17.6 million at December 31, 1999. On February 29, 2000, Westar Capital purchased the continental European and United Kingdom operations of Protection One, and certain investments held by a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Capital paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 23 of the Notes to Consolidated Financial Statements. 4
ELECTRIC UTILITY OPERATIONS General We supply electric energy at retail to approximately 628,000 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. Our electric sales volumes (excluding power marketing) for the last three years are as follows: 1999 1998 1997 ---------------------------------- (Thousands of MWH) Residential.................. 5,551 5,815 5,310 Commercial................... 6,202 6,199 5,803 Industrial................... 5,743 5,808 5,714 Wholesale and Interchange................. 5,617 4,826 5,334 Other........................ 108 108 107 ---------- ---------- ---------- Total....................... 23,221 22,756 22,268 Our electric sales for the last three years are as follows: 1999 1998 1997 ---------------------------------- (Dollars in Thousands) Residential................. $ 407,371 $ 428,680 $ 392,751 Commercial.................. 356,314 356,610 339,167 Power Marketing............. 193,421 382,601 69,827 Industrial.................. 251,391 257,186 254,076 Wholesale and Interchange................ 174,895 145,320 142,506 Other....................... 46,306 41,288 31,721 ---------- ---------- ---------- Total...................... $1,429,698 $1,611,685 $1,230,048 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 market for generation. The Energy Policy Act permitted the Federal Energy Regulatory Commission (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. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order 2000) encouraging formation of regional transmission organizations (RTOs), whose purpose is to facilitate greater competition at the wholesale level. Due to our participation in the formation of the Southwest Power Pool RTO, we anticipate that FERC Order 2000 will not have a material effect on us or our operations. 5
In December 1999, the Wichita, Kansas, City Council authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. KGE's rates are currently 7% below the national average for retail customers. The average rates charged to retail customers in territories served by our KPL division are 19% lower than KGE's rates. Customers within the Wichita metropolitan area account for approximately 25% of our total energy sales. KGE has an exclusive franchise with the City of Wichita to provide retail electric service that expires March 2002. Under Kansas law, KGE will continue to have the exclusive right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. See also Regulation and Rates below regarding a complaint filed with the FERC against KGE by the City of Wichita. 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. Regulation and Rates: As a Kansas electric utility, we are subject to the jurisdiction of the Kansas Corporation Commission (KCC) which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. We are also subject to the jurisdiction of the KCC with respect to the issuance of certain securities. Additionally, we are subject to the jurisdiction of the FERC, which has authority over wholesale sales of electricity and the issuance of certain securities. We are also subject to the jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations and safety. 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, which has authority over wholesale sales of electricity and the issuance of certain securities. KGE is also subject to the jurisdiction of the Nuclear Regulatory Commission for nuclear plant operations and safety. In September 1999, the City of Wichita filed a complaint with the FERC against KGE, alleging improper affiliate transactions between KGE and KPL, a division of Western Resources. The City of Wichita requests the FERC to equalize the generation costs between KGE and KPL, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing has been suspended pending settlement discussions between the parties. We believe that the City of Wichita's complaint is without merit and intend to defend against it vigorously. On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and KGE's rates. The KIC alleges that these rates are not 6
based on current costs. We will oppose this request vigorously but are unable to predict whether the KCC will open an investigation. Additional information with respect to Rate Matters and Regulation is set forth in Notes 1 and 15 of Notes to Consolidated Financial Statements and 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 Jeffrey Energy Center (JEC) and La Cygne 2 units have met: (1) the Federal sulfur dioxide standards through the use of low sulfur coal (See Coal); (2) the Federal particulate matter standards through the use of electrostatic precipitators; and (3) the Federal NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits. The Kansas Department of Health and Environment (KDHE) regulations, applicable to our other generating facilities, prohibit the emission of more than 3.0 pounds of sulfur dioxide per million Btu of heat input. We have 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 13 of the Notes to Consolidated Financial Statements. Fossil Fuel Generation Capacity: The aggregate net generating capacity of our system is presently 5,458 megawatts (MW). The system has interests in 22 fossil fueled steam generating units, one nuclear generating unit (47% interest), seven combustion peaking turbines, two diesel generators, and two wind generators. One unit of the 22 fossil fueled units (31 MW of capacity) that had been previously "mothballed" for future use, will be retired in 2000 (See Item 2. Properties). Our 1999 peak system net load occurred July 29, 1999, and amounted to 4,372 MW. Our net generating capacity together with power available from firm interchange and purchase contracts, 7
provided a capacity margin of approximately 12.1% above system peak responsibility at the time of the peak. We are a member of the Western Systems Power Pool (WSPP). Under this arrangement, electric utilities and marketers throughout the western United States have agreed to market energy. Services available include short-term and long-term economy energy transactions, unit commitment service, firm capacity and energy sales and energy exchanges. We are also a member of the Southwest Power Pool as discussed under Power Delivery. We have agreed to provide 42 MW of capacity and transmission service through May, 2013 to Oklahoma Municipal Power Authority (OMPA). We have another agreement to provide capacity to OMPA of 18 MW through May, 2013. We have agreed to provide Midwest Energy, Inc. (MWE) with capacity of 125 MW through May 2005, and another 61 MW through May 2007. We have agreed to provide Empire District Electric Company (Empire) with peaking and base load capacity of 80 MW through May 2000, and another 162 MW through May 2009. We also have agreed with the McPherson, Kansas Board of Public Utilities (McPherson) to provide base capacity to McPherson and McPherson to provide peaking capacity to us through May 2027. During 1999, we provided approximately 70 MW to and received approximately 187 MW from McPherson. The amount of base capacity provided to McPherson is based on a fixed percentage of McPherson's annual peak system load. Future Capacity: We are installing three new combustion turbine generators which will have installed capacity of approximately 300 MW. The first two units are scheduled to be placed in operation in June 2000, and the third is scheduled to be placed in operation in mid-2001. We estimate that the project will require $126 million in capital resources through the completion of the projects in 2001. In July 1999, we and Empire agreed to construct jointly a 500-megawatt combined cycle generating plant, which Empire will operate. We will own 40% of the generating plant and estimate that the project will require $86 million in capital resources. Construction of the plant began in the fall of 1999 with operation expected to begin in the second quarter of 2001. 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 3,366 MW of the total 5,458 MW of generating capacity and our nuclear unit provides 550 MW of capacity. Of the remaining 1,542 MW of generating capacity, units that can burn either natural gas or oil account for 1,452 MW, units that burn only diesel fuel account for 89 MW, and the remaining units which are powered by wind account for 1 MW (See Item 2. Properties). During 1999, low sulfur coal was used to produce 76% of our electricity. Nuclear produced 18% and the remainder was produced from natural gas, oil, or diesel fuel. During 2000, based on our estimate of the availability of fuel, coal will be used to produce approximately 75% of our electricity and nuclear will be used to produce approximately 17%. 8
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 1,870 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 RAG America 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 $1.11 per MMBtu, or $18.69, per ton during 1999. 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. The two coal-fired units at La Cygne Station have an aggregate generating capacity of 681 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 83% 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 2003. This low sulfur coal had an average Btu content of approximately 8,458 Btu per pound and a maximum sulfur content of .80 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. KCPL is currently negotiating an extension of rail service beyond December 31, 2000. We anticipate that the negotiation of the transportation agreements will not have a material effect on our operations. During 1999, the average delivered cost of all local and Powder River Basin coal procured for La Cygne 1 was approximately $0.78 per MMBtu, or $13.00 per ton, and the average delivered cost of Powder River Basin coal for La Cygne 2 was approximately $0.68 per MMBtu, or $11.55 per ton. The coal-fired units located at the Tecumseh and Lawrence Energy Centers have an aggregate generating capacity of 815 MW (See Item 2. Properties). The company sources low sulfur coal from Montana and Colorado under contracts through December 31, 2000. The Montana coal is transported by BNSF railroad and the Colorado coal is transported by the UP and BNSF railroads under contracts expiring December 31, 2000. Any supplemental coal required during 2000 will be purchased in the short-term market. We are currently evaluating our coal and transportation options for 2001 and will begin negotiations for new contracts during third quarter 2000. We anticipate that the negotiation of these contracts will not have a material affect on our operations. 9
The Montana coal supplied in 1999 had an average Btu content of approximately 9,359 Btu per pound and an average sulfur content of .34 lbs./MMBtu (See Environmental Matters). During 1999, the average delivered cost of Montana coal for the Lawrence units was approximately $0.92 per MMBtu, or $17.00 per ton, and the average delivered cost of Montana coal for the Tecumseh units was approximately $0.91 per MMBtu, or $17.23 per ton. The Colorado coal supplied in 1999 had an average Btu content of approximately 10,957 Btu per pound and an average sulfur content of .44 lbs/MMBtu (See Environmental Matters). During 1999, the average delivered cost of Colorado coal for the Lawrence units was approximately $1.41 per MMBtu, or $30.86 per ton, and the average delivered cost of Colorado coal for the Tecumseh units was approximately $1.39 per MMBtu, or $30.44 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. We are not substantially dependent upon these contracts due to the availability of competitive rail options. There are 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 carrier to provide service under the Interstate Commerce Act, we do not anticipate any substantial long-term disruption of our business. Natural Gas: We use natural gas as a primary fuel in our Gordon Evans, Murray Gill, 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 purchased in the short- term spot market which we believe supplies 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, 1999, we had approximately 3 million gallons of No. 2 oil and 18 million gallons of No. 6 oil in inventory 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 our weighted- average cost of fuel. 10
KPL Plants 1999 1998 1997 ---------- ----- ----- ----- Per Million Btu: Coal............. $1.09 $1.15 $1.17 Gas.............. 2.66 2.29 2.88 Oil.............. 4.17 4.40 3.72 Per KWH Generation.. 1.26 1.31 1.32 KGE Plants 1999 1998 1997 ---------- ----- ----- ----- Per Million Btu: Nuclear.......... $0.45 $0.48 $0.51 Coal............. 0.87 0.86 0.89 Gas.............. 2.31 2.28 2.56 Oil.............. 2.11 4.05 3.32 Per KWH Generation.. 0.98 0.94 1.00 Nuclear Generation The owners of Wolf Creek have on hand or under contract 100% of their uranium needs for 2000 and 77% of the uranium required to operate Wolf Creek through March 2005. 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 March 2005. Wolf Creek has active contracts for uranium enrichment with Urenco and USEC. Contracted arrangements cover 85% 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 during the ordinary course of business and is not substantially dependent upon these agreements. Wolf Creek believes there are other supplies 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 operations. Nuclear fuel is amortized to cost of sales based on the quantity of heat produced for the generation of electricity. Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. 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 the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales and are currently recovered through rates. In 1996 and 1997, a U.S. Court of Appeals (the Court) issued decisions that (1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for disposal in 1998, and (2) precluded the DOE from concluding that its delay in accepting spent fuel is "unavoidable" under its contracts with utilities due to lack of a repository or interim storage authority. In May 1998, the Court issued an order in response to the utilities' petitions for 11
remedies for DOE's failure to begin accepting spent fuel for disposal. The Court affirmed its conclusion that the sole remedy for DOE's breach of its statutory obligation under the NWPA is a contract remedy, and 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 its claims 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 begun replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025. The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (the Compact) and selected a site in Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact have provided most of the pre-construction financing for this project. Our share of Wolf Creek's net investment at December 31, 1999, was approximately $7.4 million. On December 18, 1998, the application for a license to construct this project was denied. The license applicant has sought a hearing on the license denial, but a U.S. District Court has delayed indefinitely proceedings related to the hearing. In late December 1998, the utilities filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application and seeking damages related to the utilities' costs incurred because of the delay in processing the application. In May 1999, the Nebraska legislature passed a bill withdrawing Nebraska from the Compact. In August 1999, the Nebraska governor gave official notice of the withdrawal to the other member states. Withdrawal will not be effective for five years and will not, of itself, nullify the site license proceeding. Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, Wolf Creek is able to store its low-level radioactive waste in an on-site facility for up to five years under current regulations. Wolf Creek believes that a temporary loss of low-level radioactive waste disposal capability will not affect continued operation of the power plant. Wolf Creek has an 18-month refueling and maintenance schedule which permits uninterrupted operation every third calendar year. Wolf Creek is scheduled to be taken off-line in September 2000, for its eleventh refueling and maintenance outage. During the outage, electric demand is expected to be met primarily by our coal-fired generating units. Additional information with respect to insurance coverage applicable to the operations of our nuclear generating facility is set forth in Note 13 of the Notes to Financial Statements. 12
Power Delivery Our Power Delivery segment transports electricity from the generating stations to approximately 628,000 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 and is working with us and other members to become an RTO. 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. 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, day-to- day operational interface with the KCC staff, and theft, diversion, and claims. MONITORED SERVICES General: Protection One is one of the leading providers of life safety and property monitoring services, providing electronic monitoring and maintenance of its alarm systems in 1999 to nearly 1.6 million customers in North America and Europe. Protection One also provides its customers with enhanced services that include: - Extended service protection - Patrol and alarm response - Two-way voice communication - Medical information service - Cellular back-up Approximately 85% of Protection One's revenues are contractually recurring for monitoring alarm security systems and other related services. Protection One has grown rapidly by participating in the organic growth in the alarm industry and by acquiring other alarm companies. Protection One's principal activity is responding to the security and safety needs of its customers. Protection One's sales are generated primarily from recurring monthly payments for monitoring and maintaining the alarm systems that are installed in its customers' homes and businesses. Security systems are designed to detect burglaries, fires and other events. Through a network of 57 service branches and 13 satellite offices in North America and 65 service 13
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 sold its European operations to Westar Capital on February 29, 2000. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Protection One provides its services to residential (both single family and multifamily residences), commercial and wholesale customers. At December 31, 1999, Protection One's customer base composition was as follows: Market Segment % Total ------------------------------------------- Single family and commercial..... 72% Multifamily/Apartment ........... 18% 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. Operations: Protection One's operations consist principally of alarm monitoring, customer service functions and branch operations. Security alarm systems include many different types of devices installed at customers' premises designed to detect or react to various occurrences or 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 renewals for a fixed period (typically one year) unless Protection One or the customer elect 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. In the United Kingdom, Protection One's service center was based in metropolitan London and in continental Europe, its service centers were based in Paris and in metropolitan Marseilles, France. The European operations are now owned by Westar Capital. Branch Operations: Protection One maintains approximately 57 service branches in North America from which Protection One provides field repair, customer care, alarm response and sales services and approximately 13 satellite locations from which Protection One provides field repair services. Protection One's branch infrastructure plays an important role in enhancing customer satisfaction, reducing customer loss and building brand awareness. Customer Acquisition Strategy: From November 1997 through December 1998, Protection One completed in excess of 30 transactions, adding approximately one million new customers and establishing its market position. In 1998, Protection One also expanded the dealer program for the North American single family residential market. While Protection One relied primarily on the dealer program for its growth in 1999, Protection One shifted its focus to a more diverse customer acquisition strategy including a more balanced mix of dealers, internal sales, "tuck-in" acquisitions, and direct marketing, thereby placing less reliance on account generation through the dealer program. 14
In February 2000, Protection One commenced a commission only internal sales program, with a goal of acquiring accounts at a cost lower than its external programs. Protection One is also pursuing alignments with other strategic partners in an effort to further diversify its marketing distribution channels. This program utilizes Protection One's existing branch infrastructure in 11 markets. To enhance Protection One's direct marketing efforts, Protection One entered into an agreement with Paradigm Direct LLC (Paradigm). As part of this agreement, Protection One's marketing department moved to Paradigm with the goal to improve the return on investment of marketing dollars. Westar Capital owns an approximate 40% interest in Paradigm. Network Multifamily, Inc. (Multifamily) markets its services and products primarily to developers, owners and managers of apartment complexes and other multifamily dwellings. Multifamily grows its business through national and regional advertising, a nationwide professional field sales force and affiliations with professional industry-related associations. Protection One believes this targeted internal sales effort is an effective means of generating sales in the multifamily market, which is comprised primarily of developers and professionals that can be identified and contacted with relative ease. Dealer Marketing: The dealer marketing program provides support services to dealers as they grow their independent businesses. On behalf of the dealer program participants, Protection One obtains purchase discounts on security systems, coordinates cooperative dealer advertising and provides assistance in marketing and employee training support services. 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. Competition: The security alarm industry is highly competitive and highly fragmented. In North America, there are only five alarm companies that offer services across the U.S. and Canada with the remainder being either large regional or small, privately held alarm companies. Based on number of residential customers, Protection One believes the top five alarm companies in North America are: - ADT Security Services, a subsidiary of Tyco International, Inc. (ADT) - Protection One - SecurityLink from Ameritech, Inc., a subsidiary of Ameritech Corporation - Brinks Home Security Inc., a subsidiary of The Pittston Services Group of North America - Honeywell Inc. Other alarm service companies have adopted a strategy similar to Protection One 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 its rate of growth, or to 15
increase the price paid by Protection One for customer accounts, which would adversely affect its 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 to 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 and dealers, its ability to offer combined monitoring, repair and enhanced services, its low cost structure and its marketing alliance with Paradigm. Intellectual Property: Protection One owns trademarks related to the name and logo for each of Protection One, Network Multifamily Security 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 it 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 16
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 Federal Communications Commission and state public utilities commissions regulate the operation and utilization of radio frequencies. In addition, the laws of certain of the 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 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 the loss experiences at other security service companies, may affect the availability and cost of such insurance. Certain of Protection One's 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 23 of the Notes to Consolidated Financial Statements. EMPLOYEES As of December 31, 1999, we had 7,049 employees, of which 4,659 are monitored service employees. We did not experience any strikes or work stoppages during 1999. Our current contract with the International Brotherhood of Electrical Workers extends through June 30, 2002. The contract covers approximately 1,475 employees. Approximately 970 monitored services employees in France are covered by a collective bargaining agreement. 17
RISK FACTORS The following risk factors highlight factors that may affect our financial condition and results of operation: Efforts by Wichita to Equalize Rates May Affect Operations and Results: The average rates charged to retail customers in territories served by our KPL division are 19% lower than KGE's rates. As a result of this rate disparity, the City of Wichita, Kansas has taken preliminary steps toward the creation of a municipal electric utility to replace KGE as the supplier of electricity in Wichita, including authorizing the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility. The City of Wichita has also filed a complaint with the FERC against KGE seeking to equalize the generation costs between KGE and KPL, in addition to other matters. We are unable to predict whether the City of Wichita will proceed with efforts to create a municipal electric utility and, if so, whether these efforts would be successful. We are also unable to predict whether settlement discussions between the parties in the FERC proceeding will be successful. Given the current status of these matters, the potential impact on our operations and financial condition is unclear. We can give no assurance that the impact will not be material and adverse. Deregulation May Reduce Our Earnings: Electric utilities have historically operated in a rate regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities are initiating steps that are expected to result in a more competitive environment for utility 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 our earnings which could impact our ability to pay dividends and have a material adverse impact on our operations and our financial condition. A material non-cash charge to earnings would be required should we discontinue accounting under Statement of Financial Accounting Standard No. 71 "Accounting for the Effects of Certain Types of Regulation." Downgrade in Credit Ratings Would Increase Cost of Borrowing and Reduce Earnings: Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non-utility businesses. Moody's has announced that our ratings are on review for possible downgrade. Both Standard & Poor's Rating Group and Fitch Investors Service have given our credit ratings a negative outlook. A downgrade in our credit ratings will likely increase our cost of borrowing and decrease earnings. Electric Fuel Costs are Included in Base Rates: Electric fuel costs are included in base rates. Therefore, if we wished to recover an increase in fuel costs, we would have to file a request for recovery in a rate filing with the KCC which could be denied in whole or in part. Any increase in fuel costs from the projected average which we did not recover through rates would reduce our earnings. The degree of any such impact would be affected by a variety of factors, including the amount by which fuel costs increased, and thus cannot be predicted. Purchased Power Prices are Volatile: In 1999 and 1998, the wholesale power market experienced extreme volatility in prices and supply. This volatility impacts our costs of power purchased and our participation in power trades. If we were unable to generate an adequate 18
supply of electricity for our customers, we would have to purchase power in the wholesale market or implement curtailment or interruption procedures. To the extent open positions exist in our power marketing activity, we are exposed to fluctuating market prices that may adversely impact our financial position and results of operations. The increased expenses associated with this could be material and adverse to our consolidated results of operations and financial condition. Protection One Losses Are Likely to Continue: Protection One has a history of significant net losses which are expected to continue. These losses increased in 1999, and are likely to be larger in the near future, due to accelerated amortization of customer accounts, a shorter period for amortizing goodwill, and potentially higher borrowing costs since Protection One's credit ratings have recently been downgraded. The ratings downgrade may also make it more difficult for Protection One to refinance its credit facility with Westar Capital which matures on January 2, 2001, or to obtain other capital. There can be no assurance that Protection One will attain profitable operations. The Impact of Protection One Class Action Litigation May Be Material: We, Protection One and certain of its officers are defendants in a class action litigation pending in the U.S. District Court for the Central District of Californian brought on behalf of shareholders of Protection One. The plaintiffs are seeking unspecified compensatory damages based on allegations that various statements concerning Protection One's financial results and operations for 1997 and 1998 were false and misleading. We and Protection One cannot currently predict the impact of this litigation which could be material to Protection One. See "Legal Proceedings." For additional risk factors relating to Protection One, see its December 31, 1999 Annual Report on Form 10-K/A-2. 19
EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During Past Five Years - ---- --- -------------- --------------------------- David C. Wittig 44 Chairman of the Board Executive Vice President, (since January 1999) Corporate Strategy Chief Executive Officer (May 1995 to March 1996) (since July 1998) Salomon Brothers Inc. - Managing Director, and President Co-Head of Mergers and Acquisitions (since March 1996) (1989 to 1995) Thomas L. Grennan 47 Executive Vice President, Senior Vice President, Electric Operations Electric Operations (September 1998 to November 1998) (since November 1998) Vice President, Generation Services (May 1995 to August 1998) Vice President, Electric Production (February 1994 to May 1995) Carl M. Koupal, Jr. 46 Executive Vice President Executive Vice President and Chief Administrative Corporate Communications, Officer (since July 1995) Marketing, and Economic Development (January 1995 to June 1995) Vice President, Corporate Communications, Marketing, and Economic Development (March 1992 to January 1995) Douglas T. Lake 49 Executive Vice President, Bear Stearns & Co., Inc. - Chief Strategic Officer Senior Managing Director (since September 1998) (1995 to August 1998) Dillon Read & Co. - Managing Director (1991 to 1995) William B. Moore 47 Executive Vice President, Acting Executive Vice President, Chief Financial Officer Chief Financial Officer and and Treasurer Treasurer (October 1998 - May 1999) (since May 1999) Kansas Gas and Electric Company - Chairman of the Board (June 1995 to January 1999) President (June 1995 to October 1998) Western Resources, Inc. - Vice President, Electric Division (1996) Vice President, Finance (April 1992 to June 1995) Richard D. Terrill 45 Executive Vice President, Vice President, Law and Corporate General Counsel and Secretary (July 1998-May 1999) Corporate Secretary Secretary and Associate General (since May 1999) Counsel (April 1992 to June 1998) Rita A. Sharpe 41 Vice President, Shared Westar Energy, Inc, - Services (since October Chairman and President (Feb. 1997- 1998) October 1998) Vice President and Assistant Secretary (May 1995-February 1997) Western Resources, Inc. - Manager, Interchange Sales and Accounting (1992-May 1995) 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 or she was appointed as an executive officer. 20
ITEM 2. PROPERTIES - ------------------- ELECTRIC UTILITY OPERATIONS Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) - --------------------------- ---- --------- --------- ------------- Abilene Energy Center: Combustion Turbine 1 1973 Gas 70.0 Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 151.0 2 1967 Gas--Oil 376.0 Hutchinson Energy Center: Steam Turbines 1 1950 Gas 18.0 2 1950 Gas 18.0 3 1951 Gas 28.0 4 1965 Gas 191.0 Combustion Turbines 1 1974 Gas 53.0 2 1974 Gas 52.0 3 1974 Gas 55.0 4 1975 Oil--Diesel 83.0 Diesel Generator 1 1983 Diesel 3.0 Jeffrey Energy Center (84%)(a): Steam Turbines 1 1978 Coal 625.0 2 1980 Coal 622.0 3 1983 Coal 623.0 Wind Turbines 1 1999 - 0.5 2 1999 - 0.5 La Cygne Station (50%): Steam Turbines 1 (a) 1973 Coal 344.0 2 (b) 1977 Coal 337.0 Lawrence Energy Center: Steam Turbines 2 (c) 1952 Gas 0.0 3 1954 Coal 59.0 4 1960 Coal 119.0 5 1971 Coal 394.0 Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 44.0 2 1954 Gas--Oil 74.0 3 1956 Gas--Oil 108.0 4 1959 Gas--Oil 106.0 Neosho Energy Center: Steam Turbines 3 1954 Gas--Oil 67.0 21
Unit Year Principal Unit Capacity Name No. Installed Fuel (MW) - ----------------------------------------- ---- --------- --------- -------------- Tecumseh Energy Center: Steam Turbines 7 1957 Coal 85.0 8 1962 Coal 158.0 Combustion Turbines 1 1972 Gas 20.0 2 1972 Gas 21.0 Wichita Plant: Diesel Generator 5 1969 Diesel 3.0 Wolf Creek Generating Station (47%)(a): Nuclear 1 1985 Uranium 550.0 ------- Total 5,458.0 ======= (a) The company jointly owns Jeffrey Energy Center (84%), La Cygne 1 generating unit, (50%) and Wolf Creek Generating Station (47%). (b) In 1987, KGE entered into a sale leaseback transaction involving its 50% individual interest in the La Cygne 2 generating unit. (c) Unit was previously "mothballed" for future use and will be retired in 2000. We own approximately 6,300 miles of transmission lines, approximately 20,800 miles of overhead distribution lines, and approximately 4,200 miles of underground distribution lines. Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued. MONITORED SERVICES Protection One maintains its executive offices at 6011 Bristol Parkway, Culver City, California 90230 and its main financial and administrative offices at 818 South Kansas Avenue, Topeka Kansas 66612. Protection One operates primarily from the following facilities, although Protection One leases office space for its approximate 57 service branch offices and 13 satellite branches in North America. Size Location (Sq. ft.) Lease/Own Principal Purpose - --------------------------------- --------- --------- --------------------------------------- United States: Addison, TX..................... 28,512 Lease Service Center/Administrative Headquarters Beaverton, OR................... 44,600 Lease Service Center Chatsworth, CA.................. 43,472 Lease Marketing Call Center Culver City, CA................. 23,520 Lease Former Corporate Headquarters (1) Culver City, CA................. 8,029 Lease Current Corporate Headquarters Hagerstown, MD.................. 21,370 Lease Service Center Irving, TX...................... 53,750 Lease Service Center Irving, TX...................... 54,394 Lease Administrative Functions Orlando, FL..................... 11,020 Lease Wholesale Service Center Topeka, KS...................... 6,996 Lease Financial/Administrative Headquarters Wichita, KS..................... 50,000 Own Service Center/Administrative Functions 22
Size Location (Sq. ft.) Lease/Own Principal Purpose - --------------------------------- -------- --------- --------------------------------------- Canada: Ottawa, ON...................... 7,937 Lease Service Center/Administrative Headquarters Vancouver, BC................... 5,177 Lease Service Center Europe (2): Basingstoke (London), UK............................. 3,500 Lease Financial/Administrative Headquarters/Service Center Paris, FR....................... 3,498 Lease Financial/Administrative Headquarters/Service Center Vitrolles (Marseilles) FR................. 13,003 Lease Administrative/Service Center (1) In March 2000, the lease for Protection One's former corporate headquarters was terminated. (2) On February 29, 2000, Westar Capital purchased Protection One's European operations. 23
ITEM 3. LEGAL PROCEEDINGS - -------------------------- The Securities and Exchange Commission (SEC) commenced a private investigation in 1997 relating to, among other things, 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, Westar Capital, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Monitoring), and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Ronald Cats, et al., v. Protection One, Inc., et. al.", No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. In March 2000, plaintiffs filed a Second Consolidated Amended Class Action Complaint (the Amended Complaint). Plaintiffs purport to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and notes, during the period of February 10, 1998, through November 12, 1999. The Amended Complaint asserts claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997 and 1998 were false and misleading and not in compliance with Generally Accepted Accounting Principals (GAAP). Plaintiffs allege, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Amended Complaint further asserts claims against the company and Westar as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim is also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Amended Complaint seeks an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. The company and Protection One believe that all the claims asserted in the Amended Complaint are without merit and intend to defend against them vigorously. The company and Protection One cannot currently predict the impact of this litigation which could be material to Protection One. Additional information on legal proceedings involving the company is set forth in Notes 14 and 15 of Notes to Consolidated Financial Statements 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 fiscal 1999 to a vote of the company's security holders, through the solicitation of proxies or otherwise. 24
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 March 24, 2000, there were 50,680 common shareholders of record. For information regarding quarterly common stock price ranges for 1999 and 1998, see Note 24 of Notes to Consolidated Financial Statements. Dividends Holders of Western Resources common stock are entitled to dividends when and as declared by the Board of Directors. At December 31, 1999, 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. 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. The company's board of directors reviews its dividend policy on an annual basis. Among the factors typically considered in determining its dividend policy are earnings, cash flows, capitalization ratios, competition and regulatory conditions. In January 2000, the company's board of directors declared a first-quarter 2000 dividend of 53 1/2 cents per share. In March 2000, the company announced a new dividend policy. See Note 25 of Notes to Consolidated Financial Statements for further discussion. For information regarding quarterly dividend declarations for 1999 and 1998, see Note 24 of Notes to Consolidated Financial Statements included herein. See also Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 25
ITEM 6. SELECTED FINANCIAL DATA-RESTATED - ----------------------------------------- Year Ended December 31, 1999(1) 1998(2) 1997(3) 1996 1995 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Income Statement Data: Sales...................................... $2,036,158 $2,034,054 $2,151,765 $2,046,827 $1,744,274 Net income before extraordinary gain........................ 2,554 34,058 498,652 168,950 181,676 Earnings available for common stock..................................... 13,167 32,058 493,733 154,111 168,257 December 31,............................... 1999(1) 1998(2) 1997(3) 1996 1995 ---------- ---------- ---------- ---------- ---------- (Dollars in Thousands) Balance Sheet Data: Total assets............................... $7,989,892 $7,929,776 $6,945,350 $6,647,781 $5,490,677 Long-term debt, preference stock, and other mandatorily redeemable securities. .)................. 3,103,066 3,283,064 2,391,889 1,951,583 1,641,263 Year Ended December 31,.................... 1999(1) 1998(2) 1997(3) 1996 1995 ---------- ---------- ---------- ---------- ---------- Common Stock Data: Earnings per share available for common stock before extraordinary gain...................................... $ 0.02 $ 0.46 $ 7.58 $ 2.41 $ 2.71 Earnings per share available for common stock.............................. $ 0.20 $ 0.48 $ 7.58 $ 2.41 $ 2.71 Dividends per share (4).................... $ 2.14 $ 2.14 $ 2.10 $ 2.06 $ 2.02 Book value per share....................... $ 27.66 $ 29.21 $ 30.86 $ 25.15 $ 24.71 Average shares outstanding(000's).......... 67,080 65,634 65,128 63,834 62,157 (1) Information reflects the impairment of marketable securities and a change to an accelerated amortization method for Protection One customer accounts. (2) Information reflects exit costs associated with international power development activities. (3) Information reflects the gain on the sale of Tyco common shares, our strategic alliance with ONEOK and the acquisition of Protection One. (4) In March 2000, the company announced a new dividend policy. See Note 25 of Notes to Consolidated Financial Statements for further discussion. 26
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 1999, 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 1999 - What we expect our capital expenditures to be for the years 2000 through 2002 - 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 58. These statements show our operating results for 1999, 1998 and 1997. In Management's Discussion and Analysis, we analyze and explain the significant annual changes of specific line items in the Consolidated Statements of Income. SUMMARY OF SIGNIFICANT ITEMS Extraordinary Gain on Retirement of Protection One Bonds In the fourth quarter 1999, Westar Capital purchased Protection One bonds in the open market. We have recognized an extraordinary gain of $13.4 million, net of tax, at December 31, 1999 related to the retirement of this debt. These bonds were transferred to Protection One on February 29, 2000, when Westar Capital purchased the continental European and United Kingdom operations of Protection One, and certain investments held by a subsidiary of Protection One. Marketable Securities During the fourth quarter of 1999, we decided to sell our remaining marketable security investments in paging industry companies. These securities have been classified as available-for-sale; therefore, changes in market value have been historically reported as a component of other comprehensive income. The market value for these securities declined during the last six to nine months of 1999. We determined that the decline in value of these securities was other than temporary and a charge to earnings for the decline in value was required at December 31, 1999. Therefore, we recorded a non-cash charge of $76.2 million in the fourth quarter of 1999. This charge to earnings has been presented separately in the accompanying Consolidated Statements of Income. In February 2000, Metrocall, Inc. (Metrocall), a paging company whose securities were included in our investment portfolio at December 31, 1999, made an announcement that 27
significantly increased the market value of paging company securities in the public markets. During the first quarter of 2000, we sold these paging securities and realized a gain of $24.9 million. Termination of Merger Agreement with Kansas City Power & Light Company On March 18, 1998, we signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL, and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified us that it has terminated the contemplated transaction. We expensed costs related to the KCPL merger of approximately $17.6 million at December 31, 1999. Protection One Accounting Change Protection One performed a review of its amortization policy relating to customer accounts and identified three distinct pools, each of which has distinct attributes that affect differing attrition characteristics. The pools correspond to its North America and Multifamily business segments and its former European business segment. For the North America and Europe pools, the analyzed data indicated that a change from a straight-line to a declining balance (accelerated) method would more closely match future amortization cost with the estimated revenue stream from these assets. Protection One had used a ten-year straight line amortization method for its North American pool except for customers acquired in the Westinghouse Security Systems (Westinghouse, WSS) acquisition where it determined an eight-year accelerated method was more appropriate. Protection One elected to change the rest of its North America and Europe customers to an accelerated method in the third quarter of 1999. No change was made in the method used for the Multifamily pool. See Note 1 and 2 of Notes to Consolidated Financial Statements for further discussion. Protection One Impairment Test Protection One also performed an impairment test of its customer accounts and related goodwill under the guidance of the Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (SFAS 121). Paragraph 6 of SFAS 121 indicates that an impairment loss should be recognized only if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset(s) grouped at the lowest level of identifiable cash flows. After performing the test, Protection One determined that the customer accounts are not currently impaired. Protection One Change in Estimate of Useful Life of Goodwill In conjunction with the impairment test for customer accounts, Protection One also re-evaluated the original assumptions and rationale utilized in the establishment of its carrying value and estimated useful life of goodwill. Protection One concluded that due to continued losses and increased levels of attrition experienced in 1999, the estimated useful life of goodwill should be reduced from 40 years to 20 years. As of January 1, 2000, the remaining goodwill, net of accumulated amortization, will be amortized over its remaining useful life based on a 20-year life. On Protection One's existing account base, Protection One anticipates that this will result in an increase in annual goodwill amortization of approximately $32.6 million prospectively. 28
OPERATING RESULTS Western Resources Consolidated 1999 Compared to 1998: Basic earnings per share were $0.20 compared to $0.48 in 1998. The company's 1999 results of operations benefited from the strong performance of the regulated electric utility operations. However, this strong performance was not sufficient to compensate for the changes to earnings discussed above or the performance of our monitored services business. The impact of the monitored services business on basic earning per share was $(1.02), compared to $(0.23) in 1998. 1998 Compared to 1997: Basic earnings per share were $0.48 compared to $7.58. Operating results for 1998 are difficult to compare to 1997 due primarily to 1998 charges to income and the 1997 pre-tax gain on the sale of Tyco International Ltd. (Tyco) common stock of $864.2 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 $11.5 million to reflect the impairment of assets and the closing of business activities. 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 energy sales, related cost of sales and operating expenses in 1997 for our natural gas business have been replaced by investment earnings in ONEOK. The following discussion explains significant changes from prior year results in sales, costs of sales, operating expenses, other income (expense), interest expense, income taxes, and preferred and preference dividends. Electric Utility Electric sales include sales from fossil generation, nuclear generation, power marketing and power delivery operations. The KCC and the FERC authorize rates for our electric sales. Power marketing is only regulated by the FERC. We expanded into both the marketing of electricity and risk management services to wholesale electric customers and the purchase of electricity for retail customers. 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 - The City of Wichita's attempt to create a municipal electric utility 29
- The cost of fuel included in base rates The following tables reflect the changes in electric sales volumes (excluding power marketing), for the years ended December 31, 1999, 1998 and 1997: 1999 1998 % Change ------ ------ --------- (Thousands of MWH) Residential........... 5,551 5,815 (4.5)% Commercial............ 6,202 6,199 0.1 % Industrial............ 5,743 5,808 (1.1)% Other................. 108 108 (0.2)% ------ ------ ----- Total retail......... 17,604 17,930 (1.8)% Wholesale............. 5,617 4,826 16.4 % ------ ------ ----- Total................ 23,221 22,756 2.0 % ====== ====== ===== 1998 1997 % Change ------ ------ -------- (Thousands of MWH) Residential........... 5,815 5,310 9.5 % Commercial............ 6,199 5,803 6.8 % Industrial............ 5,808 5,714 1.6 % Other................. 108 107 1.0 % ------ ------ ----- Total retail......... 17,930 16,934 5.9 % Wholesale............. 4,826 5,334 (9.5)% ------ ------ ----- Total................ 22,756 22,268 2.2 % ====== ====== ===== 1999 compared to 1998: Electric utility gross profit increased 3%, or $30.5 million. Gross profit as a percentage of sales improved to 67% from 57%. These improvements are due primarily to increased power marketing profit and increased wholesale sales. In the summer of 1999, we had increased power plant availability during hot weather when demand was high which allowed increased wholesale sales. Power plant availability impacts both gross profit and gross profit percentage, as it is more profitable for us to generate electricity for resale than to purchase power for resale. Partially offsetting these increases were lower retail sales due to weather which was milder in 1999. 1998 compared to 1997: Electric utility gross profit increased 8%, or $68.3 million. This improvement occurred because our retail sales volumes increased $66 million as a result of warmer summer temperatures but electric cost of sales only increased $4.6 million because Wolf Creek operated the entire year without any outages. Our retail sales would have been higher had we not implemented an electric rate decrease on June 1, 1998. See Note 14 of Notes to Consolidated Financial Statements for further information on our electric rate decreases. Gross profit as a percentage of sales decreased to 57% from 69%. In 1997, we made a strategic decision to expand our power marketing business to better utilize our generating assets and to reduce risk associated with energy prices. In 1997, our power marketing activity had an insignificant effect on gross profit. In 1998, we had power marketing sales of $382.6 million, but our net profit on power marketing transactions was significantly less than our net profit on our traditional electric sales. Items included in energy cost of sales are fuel expense, purchased power expense 30
(electricity we purchase from others for resale) and power marketing expense. BUSINESS SEGMENTS We have defined four business segments: fossil generation, nuclear generation, power delivery and monitored services, based on how management currently evaluates our business. Our business segments are based on differences in products and services, production processes and management responsibility. We manage our 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. 31
The following discussion identifies key factors affecting our electric business segments. 1999 1998 1997 --------- ----------- ---------- Fossil Generation: (Dollars in Thousands) External sales................. $ 365,311 $ 525,974 $ 208,836 Internal sales................. 546,683 517,363 517,167 Depreciation and amortization.. 55,320 53,132 53,831 EBIT........................... 219,087 144,357 149,825 Nuclear Generation: Internal sales................. $ 108,445 $ 117,517 $ 102,330 Depreciation and amortization.. 39,629 39,583 65,902 EBIT........................... (25,214) (20,920) (60,968) Power Delivery: External sales................. $1,064,385 $1,085,711 $1,021,212 Internal sales................. 293,522 66,492 66,492 Depreciation and amortization.. 71,717 68,297 63,590 EBIT........................... 145,603 196,398 173,809 Fossil Generation Fossil Generation's external sales include power produced for sale to external wholesale customers located outside our historical marketing territory. Internal sales include power produced for sale to Power Delivery. Internal sales are made at an internal transfer price which is based upon an assumed competitive market price for capacity and energy. 1999 compared to 1998: External sales decreased $160.7 million, or 31%, primarily due to lower power marketing sales. Power marketing sales decreased $192.5 million, or 50%, due to milder weather compared to last year. In 1999 and 1998, the wholesale power market experienced extreme volatility in prices and supply. This volatility impacts our cost of power purchased and our participation in power trades. The decrease in power marketing sales was partially offset by higher wholesale sales of $29.6 million. Due to warmer than normal weather throughout the Midwest in July and increased availability of our coal-fired generation stations, we were able to sell more electricity to wholesale customers in 1999 than in 1998. During the summer of 1998, one of our coal-fired generation units was unavailable for an extended period of time, reducing our wholesale sales capacity. The internal transfer price Fossil Generation charged Power Delivery was higher due to a higher forecasted peak demand. Therefore, internal sales and EBIT of Fossil Generation were higher. EBIT was also higher due to improved net profit on power marketing transactions. 1998 compared to 1997: External sales increased $317.1 million, mostly because of increased power marketing sales of $312.8 million. EBIT for 1998 decreased from 1997 because we had higher cost of sales of $4.6 million due primarily to a coal-fired generation station being unavailable for the summer. The 32
availability of our generating units and purchased power from other companies also impact power marketing sales. Nuclear Generation Nuclear generation has no external sales because it provides all of its power to its co-owners KGE, KCPL and Kansas Electric Power Cooperative, Inc. Internal sales include the internal transfer price that Nuclear Generation charges to Power Delivery. The amounts in the table above are our 47% share of Wolf Creek's operating results. EBIT is negative because internal sales are less than Wolf Creek's costs. Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. The next outage is scheduled in September 2000. During an outage Wolf Creek produces no power for its co-owners; therefore internal sales and EBIT decrease and nuclear fuel expense decreases. 1999 compared to 1998: Internal sales and EBIT decreased primarily due to the scheduled 36-day refueling and maintenance outage at Wolf Creek in 1999. In 1998, Wolf Creek operated the entire year without any outages. 1998 compared to 1997: Internal sales and EBIT were higher in 1998 than in 1997 because the Wolf Creek facility was off-line for 58 days in 1997 for a scheduled maintenance outage. Depreciation and amortization expense decreased $26.3 million because we had fully amortized a regulatory asset during 1997. This decrease in amortization expense increased EBIT for 1998. Power Delivery Power Delivery's external sales consist of the transmission and distribution of power to our Kansas electric customers and the customer service provided to them. Internal sales include an intra-segment transfer price for charges for the use of the distribution lines and transformers. 1999 compared to 1998: External sales decreased $21.3 million due primarily to 2% lower retail electric sales volume. Retail sales volumes decreased primarily as a result of milder temperatures in 1999. Our service territories averaged 22% fewer cooling degree days in 1999. The cumulative effect of the electric rate decreases implemented on June 1, 1998, and June 1, 1999, reduced sales by approximately $10 million. Internal sales were $227 million higher due to a change in the internal transfer price charged for the use of the distribution lines and transformers. EBIT decreased $50.8 million primarily due to $21.3 million lower external sales, a $16.1 million higher internal transfer price charged by Fossil Generation and $8.3 million in ancillary service fees charged by Fossil Generation. The increased internal transfer price was due to higher peak demand to accommodate air conditioning load. No ancillary service fees were charged by Fossil Generation in 1998. 1998 compared to 1997: External sales and EBIT increased. In addition to our normal 33
customer growth, we experienced warmer weather during the summer months in 1998 than we did in 1997 which improved external sales approximately $41.9 million. The effect of our electric rate decrease lowered 1998 external sales approximately $11 million. Monitored Services Protection One operates and manages our monitored services interest. The results discussed below reflect Protection One on a stand-alone basis and do not take into consideration the minority interest of approximately 15% at December 31, 1999 and 1998. 1999 1998 1997 ------------------------------ (Dollars in Thousands) Restated - Note 2 ------------------------------ External sales................... $605,176 $421,095 $152,347 Depreciation and amortization ... 235,465 125,103 53,292 EBIT............................. (20,675) 34,438 (37,880) 1999 compared to 1998: Protection One had a net increase of 8,595 customers in 1999 as compared to a net increase of 445,156 customers in 1998. Accordingly, results for 1999 include a full year of operations with the customers added throughout 1998. The increase in customers is the primary reason for the $184.1 million increase in external sales. EBIT decreased $55.1 million due to higher cost of sales as a result of increased customers, higher depreciation and amortization expense and higher selling general and administrative expenses. Depreciation and amortization expense increased $110.4 million. As discussed above in SUMMARY OF SIGNIFICANT ITEMS, Protection One changed its customer amortization method from a 10-year straight line method to a 10-year declining balance method for most of the North America customers and its Europe customers which increased amortization expense by approximately $39.2 million. The balance of the increase is primarily attributed to a full year of amortization expense on customers acquired during 1998. Selling, general and administrative expenses increased $71.5 million primarily due to costs associated with the overall increase in the average number of customers billed, additional bad debt expense of approximately $10.5 million resulting from higher attrition, costs associated with Year 2000 compliance, professional fees and salary increases. 1998 compared to 1997: Monitored services sales increased $268.7 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 which 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 $37.9 million. Protection One added approximately $16.6 million of monthly recurring revenue from acquisitions and approximately $5.3 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 $21.9 million of acquired monthly recurring revenue is reflected in 1998 results. Offsetting these revenue increases was Protection One's net monthly recurring revenue losses of 9%. 34
Cost of sales increased $93.4 million. Monitoring and related services expenses increased by $70.9 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 sales 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 $125.1 million in 1998. During 1998, Protection One acquired monitored services companies totaling $549 million and portfolios of customer accounts and individual new customers through its dealer program totaling $278 million. EBIT increased $72.3 million. Included in 1998 EBIT is a non-recurring gain approximating $1.5 million on the repurchase of customer contracts covered by a financing arrangement. A charge of approximately $11.5 million adversely affected 1997 EBIT. The charge was needed to reflect the impairment of certain assets and the closing of business activities. 35
Western Resources Consolidated Other Operating Expenses In 1999, we recorded a charge of $17.6 million for deferred KCPL merger costs related to the termination of the KCPL merger. In 1998, we recorded a $98.9 million charge to income associated with our decision to exit the international power project development business. Activities associated with the exit plan were substantially complete at December 31, 1999. See Note 17 of Notes to Consolidated Financial Statements for further discussion. 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 $11.5 million to reflect the impairment of certain assets and the closing of business activities. Other Income (Expense) Compared to 1998, other income for 1999 decreased $57.3 million primarily due to the other than temporary decline in the value of marketable securities recorded in 1999. Compared to 1997, other income for 1998 decreased $876.6 million primarily due to the gain recognized in 1997 on the sale of our Tyco common stock. Interest Expense 1999 compared to 1998: Interest expense represents the interest we paid on outstanding debt. Interest expense increased 30% because Protection One borrowed additional long-term debt primarily to fund purchases of customer accounts. Western Resources also had higher long-term debt interest expense because of the 6.25% and 6.8% unsecured senior notes due 2018 that we issued in third quarter of 1998. Short-term debt interest expense was $2.4 million higher due to higher average balances of short-term debt in 1999. 1998 compared to 1997: 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. Income Taxes 1999 compared to 1998: We have recorded an income tax benefit in 1999 of $32.2 million and income tax expense in 1998 of $6.8 million. This change is primarily due to lower earnings before income taxes in 1999. Earnings before income taxes decreased primarily due to operating results at Protection One, an impairment of the marketable securities discussed above and the charge related to the termination of the KCPL merger. We also had tax expense of $7.2 million related to Westar Capital's extraordinary gain on the purchase of Protection One bonds, which is presented separately on the consolidated statement of income after income from continuing operations. 36
Our effective income tax rates are affected by the receipt of non-taxable proceeds from our corporate owned life insurance policies, the tax benefit from excluding 70% of the dividends received from ONEOK, the generation and utilization of tax credits from Affordable Housing investments, the amortization of prior years' investment tax credits, and the amortization of non-deductible goodwill. 1998 compared to 1997: Income tax expense declined significantly due to the decline in taxable net income. 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. Preferred and Preference Dividends On April 1, 1998, we redeemed the 7.58% preference stock due 2007. This redemption has resulted in a significant decline in preferred and preference dividends since 1997. LIQUIDITY AND CAPITAL RESOURCES Overview Most of our cash requirements consist of capital expenditures and maintenance costs associated with the electric utility business, cash needs of our monitored services business for customer account growth and infrastructure, debt service and cash payments 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 these items with cash on hand, 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. We had $15.8 million in cash and cash equivalents at December 31, 1999. We consider highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. At December 31, 1999, we had approximately $705.4 million of short-term debt outstanding, of which $535.4 million was commercial paper. Current maturities of long-term debt were $111.7 million at December 31, 1999. As of December 31, 1999, we had arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $1.1 billion. The unused portion of these lines of credit was used to provide support for commercial paper. The unsecured short-term lines of credit included three revolving credit facilities with various banks as follows: Amount Facility Termination Date ------------------------------------------------- $300 million 364-day March 15, 2000 500 million 5-year March 17, 2003 250 million 6 1/2-month June 30, 2000 In March 2000, we amended the $300 million facility to reduce the commitment to $242 million and to extend the maturity date to June 30, 2000. We also amended all of these credit 37
facilities to reflect the possibility of borrowing from them rather than using them to provide support for commercial paper borrowings. As a result of these amendments our cost of borrowing will be higher. A one percent increase in our interest rate on our outstanding short-term debt balance as of December 31, 1999, would have increased our annual interest expense by $7 million. We cannot predict the market conditions or our credit ratings at the time we may borrow from these facilities; and therefore, cannot predict how much higher our interest expense might be. Amendments to the credit facilities include increased pricing to reflect credit quality and the potential drawn nature of credit facilities rather than support for commercial paper, redefinition of the total debt to capital financial covenant, limitation on use of proceeds from sale of first mortgage bonds requiring repayment of debt outstanding under the credit facilities before proceeds may be used for other purposes, and a commitment to use our "best efforts" to pledge first mortgage bonds to support our credit facilities if our senior unsecured credit rating drops below "investment grade" (bonds rated below BBB by Standard & Poor's (S&P) and Fitch and below Baa by Moody's Investors Service (Moody's)). In order to maintain adequate short-term borrowing capacity, we expect to replace or further amend these credit facilities prior to their termination. In January 2000, we reached an agreement with our banks under our current credit facilities to eliminate a cross-default provision relating to Protection One and its subsidiaries, provided we do not increase our investment in Protection One by more than $225 million or $125 million if our senior unsecured credit ratings drop below investment grade as determined by S&P and Moody's. We borrowed $225 million in short-term debt in 1999 to fund Westar Capital's revolving credit agreement to Protection One. We may borrow additional short- term debt from time-to-time to fund Protection One's revolving credit agreement. We have registered securities for sale with the Securities and Exchange Commission (SEC). As of December 31, 1999, these included $400 million of unsecured senior notes, $50 million of KGE first mortgage bonds and approximately 11.2 million Western Resources common shares. Our ability to issue additional debt and equity securities is restricted under limitations imposed by the charters and the Mortgage and Deed of Trusts of Western Resources and KGE. Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our unconsolidated 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, 1999, $410 million of first mortgage bonds could be issued (8.25% interest rate assumed). Our 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, 1999, we had approximately $365 million of net bondable property additions not subject to an unfunded prior lien entitling us to issue up to $219 million principal amount of additional bonds. As of December 31, 1999, $125 million in additional first mortgage bonds could be issued on the basis of retired bonds. 38
KGE's mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless KGE's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not either 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. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. Based on KGE's results for the 12 months ended December 31, 1999, approximately $1.0 billion principal amount of additional KGE first mortgage bonds could be issued (8.25% interest rate assumed) under the most restrictive tests in the mortgage. As of December 31, 1999, $17 million in additional bonds could be issued on the basis of retired bonds. We plan to sell, subject to market and other conditions, up to $500 million of first mortgage bonds in 2000. S&P, Fitch Investors Service (Fitch) and Moody's are independent credit- rating agencies that rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal on these securities. 39
As of March 24, 2000, ratings with these agencies were as follows: Western Western KGE's Protection Protection Resources' Western Resources' KGE's Senior One One Mortgage Resources' Short-term Mortgage Unsecured Senior Senior Bond Unsecured Debt Bond Debt Unsecured Subordinated Rating Agency Rating Debt Rating Rating Rating Debt Unsecured Debt - ------------- ---------- --------- ---------- ---------- --------- --------- -------------- S&P A- BBB A-2 BBB+ BBB BB- B Fitch A- BBB+ F-2 A- - BB B+ Moody's A3 Baa1 P-2 A3 Baa3 B2 Caa1 Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non- utility businesses. In January 2000,in response to the terminated KCP&L merger and unprofitable operations and liquidity issues at Protection One, Moody's announced they were placing Western Resources and KGE ratings on review for possible downgrade, S&P affirmed its ratings of Western Resources and KGE, but said the outlook is negative, and Fitch placed the ratings of Western Resources and KGE on RatingAlert - Negative. We anticipate that these rating agencies will complete their reviews and lower our credit ratings in the near future, but we cannot predict our new ratings. In response to liquidity and operational issues and our announcement that we are exploring strategic alternatives for Protection One, in November 1999, Moody's, S&P and Fitch downgraded their ratings on Protection One's credit facility and outstanding securities. On March 24, 2000, Moody's further downgraded their ratings on Protection One's outstanding securities with outlook remaining negative. Should our short-term debt ratings be lowered, access to the commercial paper market, when available, would be more costly and may require borrowing from our existing revolving credit facilities. Cash Flows from Operating Activities Cash from operations decreased 6% in 1999 compared to 1998. This decrease was primarily due to lower net income in 1999 and higher amortization expense recorded by Protection One. Cash Flows Used In Investing Activities Cash used in investing activities decreased 62% primarily due to fewer acquisitions of monitored services companies and customer accounts and fewer purchases of marketable securities than in 1998. This decrease was offset by higher capital expenditures in 1999. Cash Flows from Financing Activities Cash from financing activities decreased 86% because we issued less debt as a result of fewer acquisitions by Protection One in 1999 compared to 1998. The decrease in long-term debt proceeds was offset by increased short-term borrowings used to fund Westar Capital's revolving credit agreement to Protection One. In July 1999, we announced a stock repurchase program for up to $25 million of our common stock. In 1999, we purchased 900,000 shares of common stock at an average price of $17.55 per share. In January 2000, we purchased another 540,000 shares of common stock at an average price of $17.01 per share to complete our repurchase of approximately $25 million in common stock. All of these purchased shares will be held in treasury and will be available for general 40
corporate purposes or resale at a future date. We may make additional repurchases of shares from time to time in the open market or in private transactions. We may also make additional purchases of Protection One bonds from time to time in the open market. Future Cash Requirements We believe that internally generated funds and access to capital markets will be sufficient to meet our operating and capital expenditure requirements, debt service and dividend payments through the year 2002. Uncertainties affecting our ability to meet these requirements with internally generated funds include the factors affecting sales described above, the impact of inflation on operating expenses, regulatory actions, and compliance with future environmental regulations, and the impact of Protection One's operations and financial condition. Additionally, our ability to access capital markets will affect the new and existing credit agreements we have available to meet our operating and capital expenditure requirements, debt service and dividend payments. We plan to install three new combustion turbine generators with an installed capacity of approximately 300 MW. The first two units are scheduled to be placed in operation in June 2000, and the third is scheduled to be placed in operation in mid-2001. We estimate that the project will require $126 million in capital resources through the completion of the projects in 2001. In July 1999, we agreed with Empire to construct jointly a 500-megawatt combined cycle generating plant, which Empire will operate. We estimate that our share of the project will require an estimated $86 million in capital resources and that we will own 40% of the generating plant. Construction of the plant began in the fall of 1999 with operation expected to begin in the second quarter of 2001. Our business requires a significant capital investment. We currently expect that through the year 2002, we will need cash mostly for: - Ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. - Improving operations within the monitored services business and the acquisition of customer accounts. Capital expenditures for 1999 and anticipated capital expenditures for 2000 through 2002 are as follows: Fossil Nuclear Power Monitored Generation Generation Delivery Services Other Total -------------------------------------------------------------- (Dollars in Thousands) 1999. . . $143,900 $10,000 $89,200 $273,600 $20,200 $536,900 2000. . . 162,800 31,600 86,100 93,400 3,900 377,800 2001. . . 84,400 19,600 86,700 132,800 100 323,600 2002. . . 54,800 20,300 85,500 135,600 - 296,200 Monitored Services includes capital expenditures for Protection One North America and Protection One Europe, including purchases of customer accounts. Other represents our 41
commitment to fund our Affordable Housing Tax Credit program. These estimates are prepared for planning purposes and may be revised (See Note 13 of Notes to Consolidated Financial Statements). Actual expenditures may differ from our estimates. Maturities of long-term debt through 2004 are as follows: Principal Year Amount ----------------------------- (Dollars in Thousands) 2000................ $111,667 2001................ 32,246 2002................ 106,472 2003................ 240,568 2004................ 370,457 Capital Structure Our capital structures at December 31, 1999, and 1998 were as follows: 1999 1998 1997 ----- ----- ----- Shareholders' equity (excluding preferred stock).................................... 38% 37% 46% Preferred stock............................. 1% 1% 1% Western Resources obligated mandatorily redeemable preferred securities of subsidiary trust holding solely company subordinated debentures.... 4% 4% 5% Long-term debt.............................. 57% 58% 48% ---- ---- ---- Total....................................... 100% 100% 100% Dividend Policy Our board of directors reviews our dividend policy on an annual basis. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, competition and regulatory conditions. In January 2000, our board of directors declared a first- quarter 2000 dividend of 53 1/2 cents per share. In March 2000, we announced a new dividend policy. See Note 25 of Notes to Consolidated Financial Statements for further discussion. OTHER INFORMATION Electric Utility City of Wichita Proceeding: In December 1999, the Wichita, Kansas, City Council authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. KGE's rates are currently 7% below the national average for retail customers. The average rates charged to retail customers in territories served by our KPL division are 19% lower than KGE's rates. The City of Wichita has filed a complaint with the FERC requesting the FERC to equalize 42
the generation costs between KGE and KPL, in addition to other matters (see also FERC Proceeding below). Customers within the Wichita metropolitan area account for approximately 25% of our total energy sales. KGE has an exclusive franchise with the City of Wichita to provide retail electric service that expires March 2002. Under Kansas law, KGE will continue to have the exclusive right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. KGE will oppose any attempt by the City of Wichita to eliminate it as the electric provider to Wichita customers. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system. KCC Proceeding: On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and KGE's rates. The KIC alleges that these rates are not based on current costs. We will oppose this request vigorously but are unable to predict whether the KCC will open an investigation. FERC Proceeding: In September 1999, the City of Wichita filed a complaint with the FERC against us, alleging improper affiliate transactions between KPL, one of our divisions, and KGE, our wholly-owned subsidiary. The City of Wichita requests the FERC to equalize the generation costs between KPL and KGE, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing has been suspended pending settlement discussions between the parties. We believe that the City of Wichita's complaint is without merit and intend to defend against it vigorously. Competition and Deregulation: 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 market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. 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. During 1999, wholesale electric sales represented approximately 14% of total electric sales, excluding power marketing sales. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order 2000) encouraging formation of regional transmission organizations (RTOs), whose purpose is to facilitate greater competition at the wholesale level. Due to our participation in the formation of the Southwest Power Pool RTO, we anticipate that FERC Order 2000 will not have a material effect on us or our operations. 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 1999 and 2000 legislative sessions, but none passed in 1999 and none are expected to pass in 2000. When retail wheeling will be implemented by the legislature in Kansas remains uncertain. 43
If retail wheeling is implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. 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. Our rates range from approximately 75% to 93% of the national average for retail customers. Because of these reduced rates, we expect to retain a substantial part of our current volume of sales volumes in a competitive environment. We also expect we can maintain profitable prices in a competitive environment, given how our current rates compare to the national average rates. We offer competitive electric rates for industrial improvement projects and economic development projects in an effort to maintain and increase electric load. Stranded Costs: The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets which exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our fossil generation, nuclear generation and power delivery operations. If we determine that we no longer meet the criteria of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71), we may have a material extraordinary non-cash charge to operations. Reasons for discontinuing SFAS 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred and a significant change by regulators from a cost-based rate regulation to another form of rate regulation. We periodically review SFAS 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS 71 accounting treatment based upon competitive or other events, we may significantly impact the value of our net regulatory assets and our utility plant investments, particularly the Wolf Creek nuclear generation facility. Regulatory changes, including competition, could adversely impact our ability to recover our investment in these assets. As of December 31, 1999, we have recorded regulatory assets which are currently subject to recovery in future rates of approximately $366 million. Of this amount, $218.2 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 debt issuance costs, deferred employee benefit costs, deferred plant costs, and coal contract settlement costs. In a competitive environment, we may not be able to fully recover our entire investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. 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. Nuclear Decommissioning: Decommissioning is a nuclear industry term for the permanent shut-down of a nuclear power plant. 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 to fund decommissioning. These plans are designed so that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant. 44
The Financial Accounting Standards Board (FASB) is reviewing the accounting for closure and removal costs, including decommissioning of nuclear power plants. The FASB has issued an Exposure Draft "Accounting for Obligations Associated with the Retirement of Long-Lived Assets." The proposed Statement is to be effective for fiscal years beginning after June 15, 2001. If current accounting practices for nuclear power plant decommissioning are changed, the following could occur: - Our annual decommissioning expense could be higher than in 1999 - 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 change, if required, would adversely affect our operating results due to our current ability to recover decommissioning costs through rates (See Note 12 of Notes to Consolidated Financial Statements). Collective Bargaining Agreement: Our contract with the International Brotherhood of Electrical Workers (IBEW) was renewed on January 20, 2000, and will be due for renewal July 1, 2002. The contract covers approximately 1,475 employees. As of December 31, 1999, we had 7,049 employees. Year 2000 Issue: Our electric utility operations experienced no business disruptions as a result of the transition from December 31, 1999, to January 1, 2000, or as a result of "leap day" on February 29, 2000. We estimated that total costs to update all of our electric utility operating systems for Year 2000 readiness, excluding costs associated with WCNOC, would be approximately $6.3 million. As of December 31, 1999, we expensed $6.3 million for these purposes. We expect to incur minimal cost in 2000 to complete remediation of less important systems. We expect no Year 2000 issues to arise in 2000. WCNOC experienced no business disruptions as a result of the transition from December 31, 1999, to January 1, 2000, or as a result of "leap day" on February 29, 2000. WCNOC has estimated the costs to complete the Year 2000 project at $3.5 million ($1.7 million, our share). As of December 31, 1999, WCNOC expensed $3.2 million ($1.5 million our share), to complete remediation and testing of mission critical systems necessary to continue to provide electrical service to our customers. WCNOC expects to incur $0.2 million (our share) in 2000 to complete remediation of less important systems. WCNOC expects no Year 2000 issues to arise in 2000. Monitored Services Attrition: During 1999, Protection One experienced an increase in customer attrition. Total attrition for the twelve months ended December 31, 1999 was 14.0% compared to 9.4% for the same period ended December 31, 1998. Annualized total attrition for the quarter ended December 31, 1999, was 14.7% compared to 16.0% for the quarter ended September 30, 1999. Customer attrition by Protection One's business segments is summarized below for the period ended December 31. Trailing Twelve Month December 31, 1999 1998 ---- ---- 45
North America........... 16.0% 11.0% Multifamily............. 7.6% 4.6% Europe (1).............. 9.6% - Total Protection One.. 14.0% 9.4% (1) Protection One acquired the European operations in 1998. Sale of Mobile Services Group: On August 25, 1999, Protection One sold its Mobile Services Group to ATX Technologies (ATX). The sales price was approximately $20 million in cash plus a note and a preferred stock investment in ATX. In August, Protection One recorded a gain on the sale of approximately $11 million, net of tax. Year 2000 Issue: Protection One experienced no business disruptions as a result of the transition from December 31, 1999 to January 1, 2000, or as a result of "leap day" on February 29, 2000. As of December 31, 1999, Protection One expensed $4.3 million to complete remediation and testing of mission critical systems necessary to continue to provide monitored services to its customers. Protection One expects to incur minimal costs in 2000 to complete remediation of less important systems. Protection One expects no Year 2000 issues to arise in 2000. Related Party Transactions We and ONEOK have shared services agreements in which we provide and bill for facilities, utility field work, information technology, customer support, bill processing and human resources services to one another. Payments for these services are based upon various hourly charges, negotiated fees and out-of- pocket expenses. In 1999 and 1998, ONEOK paid us $5.6 million and $4.9 million, net of what we owed ONEOK, for services. As a result of Protection One not meeting its debt covenants, in December 1999, Westar Capital, acquired the debt and assumed the lenders' obligations under Protection One's revolving credit facility. We loaned Westar Capital approximately $225 million for this purpose. As of February 29, 2000, we had spent $42.4 million to acquire Protection One non-convertible debt securities through open market transactions. In the first quarter of 2000, Westar Capital transferred to Protection One certain outstanding Protection One debt securities for partial payment of certain outstanding intercompany amounts owed to Protection One. On February 29, 2000, Westar Capital purchased the continental European and United Kingdom operations of Protection One, and certain investments held by a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Capital paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Westar Capital has agreed to pay Protection One a portion of the net gain, if any, on a subsequent sale of the European businesses on a declining basis over the four years following the closing. Cash proceeds from the transaction were used to reduce the outstanding balance owed to Westar Capital on Protection One's revolving credit facility. Concurrently, Westar Capital and Protection One amended the revolving credit agreement to reduce the facility from $250 million to $115 million and to change the maturity date to January 2, 2001. For approved acquisitions, an additional $40 million could be made available under the facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected. We may acquire additional Protection One debt securities. The timing and terms of 46
purchases, and the amount of debt actually purchased, will be based on market conditions and other factors. Purchases are expected to be made in the open market or through negotiated transactions. Because Protection One's debt currently trades at less than its carrying value, we would expect to realize an extraordinary gain on extinguishment of debt on any purchases. Investment in Gas Compression Company As of December 31, 1999, we owned less than 10% of the outstanding common stock of a gas compression company through our Westar Capital subsidiary. We have determined that this investment is not strategic to our ongoing business and are selling the common stock. During 1999, we recorded a $9.3 million gain on the sale of a portion of this investment. During the first quarter of 2000, we sold a significant portion of this investment and realized a gain of $72.6 million through March 16, 2000. Market Risk Disclosure Market Price Risks: We are exposed to market risk, including changes in commodity prices, equity instrument investment prices and interest rates. Commodity Price Exposure: In 1999, we engaged in both trading and non- trading activities in our commodity price risk management activities. We primarily traded electricity commodities. We utilized 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 were involved in trading activities primarily to minimize risk from market fluctuations, to maintain a market presence and to enhance system reliability. We attempted to balance our physical and financial purchase and sale contracts in terms of quantities and contract terms. Net open positions existed or were established due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we had open positions, we were exposed to the risk that fluctuating market prices could adversely impact our financial position or results from operations. In 2000, we expect to operate our trading activities in a similar manner as 1999. 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 the VAR 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. Our Risk Oversight Committee sets the VAR limit. The high, low and average VAR amounts for the year ended December 31, 1999, were $395,115, $26,039 and $68,832. We employ additional risk control mechanisms such as stress testing, daily loss limits, and commodity position limits. We expect to use the same VAR model and VAR limits in 2000. We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with 47
the financial condition of counterparties, product location (basis) differentials and other risks which management policy dictates. The counterparties in our portfolio are primarily large energy marketers and major utility companies. The creditworthiness of our counterparties could positively or negatively impact our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in 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. From 1998 to 1999, we experienced a 27% increase in price per MW of electricity purchased for utility operations. If we were to have a similar increase from 1999 to 2000, given the amount of power purchased for utility operations during 1999, we would have an exposure of approximately $6.3 million of net income. Due to the volatility of the power market, there are no indications that past performance can be used to predict the future. We use a mix of various fuel types to operate our system. From 1998 to 1999, we experienced a 4% increase in the average price per MMBtu of natural gas purchased for utility operations. From 1998 to 1999, we experienced less than a 1% change in price per MMBtu for all fuel types purchased for our system. Based on MMBtu's of natural gas and fuel oil burned during 1999, we would have exposure in 2000 of approximately $4.7 million of net income for a 10% change in average price paid per MMBtu. Due to the volatility of natural gas prices, there are no indications that past performance can be used to predict the future. Quantities of natural gas and electricity could vary dramatically year to year based on weather, unit outages and nuclear refueling. Equity Price Risk: We had approximately $111.9 million of equity securities as of December 31, 1999. Through March 16, 2000, we sold a material portion of these equity securities and recognized a $72.6 million gain. Following the sale of these equity securities, we have $29.9 million of equity securities. 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 as an adjustment to shareholders' equity. Declines in market value which are other than temporary are recognized in income. The market price of equity securities still owned at December 31, 1999, increased by 34% from 1998 to 1999. During the first quarter of 2000, the market price of these equity securities increased 5%. An immediate 10% change in the market price of our remaining equity securities would have a $3.0 million effect on fair value. Interest Rate Exposure: We have approximately $827.4 million of variable rate debt, including current maturities of fixed rate debt, as of December 31, 1999. Our weighted average interest rate increased from 5.94% at December 31, 1998 to 6.96% at December 31, 1999. A 100 basis point change in each debt series benchmark rate would impact net income on an annual basis by approximately $9.2 million. In response to the terminated KCP&L merger and unprofitable operations and liquidity issues at Protection One, Moody's, S&P, and Fitch are reviewing our securities ratings. Should our short-term debt ratings be lowered, access to the commercial paper market, when available, would be more costly and may require borrowing from our existing revolving credit facilities. We cannot predict the market conditions or our credit ratings at the time we may borrow from these facilities; and therefore, cannot predict how much higher our interest expense might be. Due to Protection One's liquidity and operational issues and the announcement by Western 48
Resources that we are exploring strategic alternatives for Protection One, in November 1999, Moody's, S&P and Fitch downgraded their ratings on Protection One's credit facility and outstanding securities. On March 24, 2000, Moody's further downgraded their ratings on our outstanding securities with outlook remaining negative. During the first quarter of 2000, we sold our remaining portfolio of marketable debt securities and realized a gain of approximately $24.9 million. Therefore, we have no further interest rate exposure related to marketable debt securities. Foreign Currency Exchange Rates: We have overseas operations with functional currencies other than the United States dollar. As of December 31, 1999, the unrealized loss on currency translation, presented as a separate component of stockholders' equity and reported within other comprehensive income was approximately $1.3 million pretax. A 10% change in the currency exchange rates would have an immaterial effect on other comprehensive income. Pronouncements Issued but Not Yet Effective In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). In June 1999, the FASB issued Statement No. 137 "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in hybrid contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. With respect to hybrid contracts, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998. SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met and that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, in part, allows special hedge accounting for fair value and cash flow hedges. We have no fair value hedges as of December 31, 1999. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. If SFAS 133 were required to be applied to cash flow hedges in place at December 31, 1999, changes in the fair value of options and forwards would contribute approximately $1.3 million of additional loss to other comprehensive income for the twelve months ended December 31, 1999, if these hedges were 100% effective. We are still in the process of evaluating the effectiveness of these hedges. We use derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of cash market prices. Specifically, anticipated purchases of electricity are being hedged using options and forwards. We currently record our cash flow hedges as assets and liabilities on our Consolidated Balance Sheet. We mark the hedges to market on the Consolidated Balance Sheet at the end of each period. We recognize the realized gains and losses in net income in the period the options and forwards are settled. SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 49
133 cannot be applied retroactively. We are currently evaluating commodity contracts and financial instruments to determine what, if any, effect of adopting SFAS 133 might have on our financial statements. We have not yet quantified all effects of adopting SFAS 133 on our financial statements; however, SFAS 133 could increase volatility in earnings and other comprehensive income. We plan to adopt SFAS 133 as of January 1, 2001. 50
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. 51
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ---------------------------------------------------- TABLE OF CONTENTS PAGE Report of Independent Public Accountants 53 Financial Statements: Consolidated Balance Sheets, December 31, 1999, 1998 and 1997 54 Consolidated Statements of Income for the years ended December 31, 1999, 1998 and 1997 55 Consolidated Statements of Comprehensive Income for the years ended December 31, 1999, 1998 and 1997 56 Consolidated Statements of Cash Flows for the years ended 1999, 1998 and 1997 57 Consolidated Statements of Cumulative Preferred and Preference Stock December 31, 1999, 1998 and 1997 58 Consolidated Statements of Shareholders' Equity for the years ended December 31, 1999, 1998 and 1997 59 Notes to Consolidated Financial Statements 60 Financial Schedules: Schedule II - Valuation and Qualifying Accounts 106 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. 52
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., as of December 31, 1999, 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, 1999 (1999, 1998 and 1997 as restated. See Note 2 of Notes to Consolidated Financial Statements). These 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 financial statements and this schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc., as of December 31, 1999, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the Financial Statements, effective September 1, 1999, the company changed its method of amortization for customer accounts for its North American and European customers from the straight-line method to a declining balance (accelerated) method. 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. Kansas City, Missouri, ARTHUR ANDERSEN March 16, 2000 (except with respect to the Dividend Policy and Corporate Restructuring discussed in Note 25, as to which the date is March 28, 2000, and the matter discussed in Note 2, as to which the date is February 1, 2001) 53
WESTERN RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) December 31, -------------------------------------- 1999 1998 1997 ---------- ---------- ---------- (Restated) -------------------------------------- ASSETS CURRENT ASSETS: Cash and cash equivalents............................. $ 15,827 $ 16,394 $ 76,608 Accounts receivable (net)............................. 229,200 218,243 325,043 Inventories and supplies (net)........................ 112,392 95,590 86,398 Marketable securities................................. 177,128 288,077 75,258 Prepaid expenses and other............................ 68,421 57,225 25,483 ---------- ---------- ---------- Total Current Assets................................ 602,968 675,529 588,790 ---------- ---------- ---------- PROPERTY, PLANT AND EQUIPMENT (NET)..................... 3,889,444 3,799,916 3,786,528 ---------- ---------- ---------- OTHER ASSETS: Investment in ONEOK................................... 590,109 615,094 596,206 Customer accounts (net)............................... 1,131,932 1,005,336 540,722 Goodwill (net)........................................ 1,057,041 1,141,921 797,211 Regulatory assets..................................... 366,004 364,213 380,421 Other................................................. 352,394 327,767 255,472 ---------- ---------- ---------- Total Other Assets.................................. 3,497,480 3,454,331 2,570,032 ---------- ---------- ---------- TOTAL ASSETS............................................ $7,989,892 $7,929,776 $6,945,350 ========== ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt.................. $ 111,667 $ 165,838 $ 22,525 Short-term debt....................................... 705,421 312,472 236,500 Accounts payable...................................... 132,834 127,834 151,166 Accrued liabilities................................... 226,786 252,367 222,410 Accrued income taxes.................................. 40,328 32,942 27,360 Deferred security revenues............................ 61,148 57,703 33,900 Other................................................. 73,011 85,690 47,737 ---------- ---------- ---------- Total Current Liabilities........................... 1,351,195 1,034,846 741,598 ---------- ---------- ---------- LONG-TERM LIABILITIES: Long-term debt (net).................................. 2,883,066 3,063,064 2,171,889 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company subordinated debentures.............. 220,000 220,000 220,000 Deferred income taxes and investment tax credits...... 976,135 931,079 1,070,129 Minority interests.................................... 192,734 204,723 166,811 Deferred gain from sale-leaseback..................... 198,123 209,951 221,779 Other................................................. 279,451 316,245 259,521 ---------- ---------- ---------- Total Long-Term Liabilities......................... 4,749,509 4,945,062 4,110,129 ---------- ---------- ---------- COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY: Cumulative preferred and preference stock............. 24,858 24,858 74,858 Common stock, par value $5 per share, authorized 150,000,000 shares, outstanding 67,401,657 and 65,909,442 shares and 65,409,603 respectively....... 341,508 329,548 327,048 Paid-in capital....................................... 820,945 775,337 760,553 Retained earnings..................................... 679,880 810,617 919,045 Accumulated other comprehensive income................ 37,788 9,508 12,119 Treasury stock, at cost, 900,000 and 0 shares, respectively....................................... (15,791) - - ---------- ---------- ---------- Total Shareholders' Equity.......................... 1,889,188 1,949,868 2,093,623 ---------- ---------- ---------- TOTAL LIABILITIES & SHAREHOLDERS' EQUITY................ $7,989,892 $7,929,776 $6,945,350 ========== ========== ========== The Notes to Consolidated Financial Statements are an integral part of this statement. 54
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME (Dollars in Thousands, Except Per Share Amounts) Year Ended December 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (Restated) ------------------------------------ SALES: Energy............................................... $ 1,430,982 $ 1,612,959 $ 1,999,418 Security............................................. 605,176 421,095 152,347 ----------- ----------- ----------- Total Sales........................................ 2,036,158 2,034,054 2,151,765 ----------- ----------- ----------- COST OF SALES: Energy............................................... 478,982 691,468 928,723 Security............................................. 184,005 131,791 38,800 ----------- ----------- ----------- Total Cost of Sales................................ 662,987 823,259 967,523 ----------- ----------- ----------- GROSS PROFIT........................................... 1,373,171 1,210,795 1,184,242 ----------- ----------- ----------- OPERATING EXPENSES: Operating and maintenance expense.................... 337,068 337,507 384,313 Depreciation and amortization........................ 403,669 288,125 268,838 Selling, general and administrative expense.......... 342,652 263,310 316,479 International power development costs................ (5,632) 98,916 - Deferred merger costs................................ 17,600 - 48,008 Monitored services special charge.................... - - 11,542 ----------- ----------- ----------- Total Operating Expenses........................... 1,095,357 987,858 1,029,180 ----------- ----------- ----------- INCOME FROM OPERATIONS................................. 277,814 222,937 155,062 ----------- ----------- ----------- OTHER INCOME (EXPENSE): Impairment of marketable securities.................. (76,166) - - Investment earnings.................................. 35,979 49,797 44,978 Gain on sale of Tyco securities...................... - - 864,253 Minority interests................................... 12,600 2,762 2,305 Other................................................ 14,234 (8,563) 9,071 ----------- ----------- ----------- Total Other Income (Expense)....................... (13,353) 43,996 920,607 ----------- ----------- ----------- EARNINGS BEFORE INTEREST AND TAXES..................... 264,461 266,933 1,075,669 INTEREST EXPENSE....................................... 294,104 226,120 193,808 ----------- ----------- ----------- (LOSS) EARNINGS BEFORE INCOME TAXES.................... (29,643) 40,813 881,861 INCOME TAX (BENEFIT) EXPENSE........................... (32,197) 6,755 383,209 ----------- ----------- ----------- NET INCOME BEFORE EXTRAORDINARY GAIN................... 2,554 34,058 498,652 EXTRAORDINARY GAIN, NET OF TAX......................... 11,742 1,591 - ----------- ----------- ----------- NET INCOME............................................. 14,296 35,649 498,652 PREFERRED AND PREFERENCE DIVIDENDS..................... 1,129 3,591 4,919 ----------- ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK.................... $ 13,167 $ 32,058 $ 493,733 =========== =========== =========== AVERAGE COMMON SHARES OUTSTANDING...................... 67,080,281 65,633,743 65,127,803 BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING: Earnings available for common stock before extraordinary gain................................. $ 0.02 $ 0.46 $ 7.58 Extraordinary gain................................... 0.18 0.02 - ----------- ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK.................... $ 0.20 $ 0.48 $ 7.58 =========== =========== =========== DIVIDENDS DECLARED PER COMMON SHARE.................... $ 2.14 $ 2.14 $ 2.10 The Notes to Consolidated Financial Statements are an integral part of this statement. 55
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in Thousands) Year Ended December 31, -------------------------------- 1999 1998 1997 -------- -------- -------- (Restated) -------------------------------- NET INCOME................................................. $ 14,296 $ 35,649 $498,652 -------- -------- -------- OTHER COMPREHENSIVE INCOME (LOSS), BEFORE TAX: Unrealized holding (losses) gains on marketable securities arising during the year..................... (55,420) (17,244) 25,248 Less: Reclassification adjustment for losses included in net income................................. 102,417 14,029 - -------- -------- -------- Unrealized gain (loss) on marketable securities (net).... 46,997 (3,215) 25,248 Unrealized loss on currency translation.................. (115) (1,026) - -------- -------- -------- Other comprehensive income (loss), before tax.......... 46,882 (4,241) 25,248 -------- -------- -------- INCOME TAX (BENEFIT) EXPENSE............................... 18,602 (1,630) 13,129 -------- -------- -------- OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX.............. 28,280 (2,611) 12,119 -------- -------- -------- COMPREHENSIVE INC0ME....................................... $ 42,576 $ 33,038 $510,771 ======== ======== ======== The Notes to Consolidated Financial Statements are an integral part of this statement. 56
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) Year ended December 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (Restated) ------------------------------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income............................................. $ 14,296 $ 35,649 $ 498,652 Adjustments to reconcile net income to net cash provided by operating activities: Extraordinary gain..................................... (11,742) (1,591) - Depreciation and amortization.......................... 403,669 288,125 268,838 Amortization of gain on sale-leaseback................. (11,828) (11,828) (11,281) Equity in earnings from investments.................... (8,199) (6,064) (25,405) Gain on sale of Mobile Services........................ (17,249) - - Minority interests..................................... (12,600) (2,762) (2,305) (Gain)/loss on sale of securities...................... 26,251 14,029 (864,253) Impairment of marketable securities.................... 76,166 - - Accretion of debt premium.............................. (6,799) 3,034 1,026 International development costs........................ (5,632) 98,916 - Net deferred taxes..................................... (15,825) (57,119) (25,084) Deferred merger costs.................................. 17,600 - 48,008 Monitored services special charge...................... - - 11,542 Changes in working capital items (net of effects from acquisitions): Accounts receivable (net)............................ (3,824) 118,844 14,156 Inventories and supplies (net)....................... (15,024) (8,000) 3,249 Prepaid expenses and other........................... (17,742) (26,988) 9,230 Accounts payable..................................... 5,000 (33,613) (48,298) Accrued liabilities.................................. (20,152) (42,411) 68,623 Accrued income taxes................................. 7,386 5,582 9,869 Deferred revenue..................................... 3,479 (2,237) 670 Other................................................ (3,518) 58,519 (9,254) Changes in other assets and liabilities................ (30,485) (29,873) (26,079) ---------- ---------- ---------- Net cash flows from (used in) operating activities... 373,228 400,212 (78,096) ---------- ---------- ---------- CASH FLOWS USED IN INVESTING ACTIVITIES: Additions to property, plant and equipment (net)....... (275,744) (182,885) (207,989) Customer account acquisitions.......................... (241,000) (277,667) (45,163) Monitored services acquisitions, net of cash acquired................................. (27,409) (549,196) (438,717) Divestiture of Mobile Services......................... 19,087 - - Proceeds from issuance of stock by subsidiary (net).... - 45,565 - Purchases of marketable securities..................... (12,003) (261,036) (10,461) Proceeds from sale of marketable securities............ 73,456 27,895 1,533,530 Investment in Paradigm................................. (35,883) - - Sale of ONEOK Stock.................................... 28,101 - - Purchase of Protection One bonds....................... (19,671) - - Other investments (net)................................ 4,251 (91,451) (45,318) ---------- ---------- ---------- Net cash flows (used in) from investing activities... (486,815) (1,288,775) 785,882 ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-term debt (net).................................. 392,949 75,972 (744,240) Proceeds of long-term debt............................. 16,000 1,096,238 520,000 Retirements of long-term debt.......................... (178,350) (167,068) (293,977) Issuance of common stock (net)......................... 43,245 17,284 25,042 Redemption of preference stock......................... - (50,000) - Cash dividends paid.................................... (145,033) (144,077) (141,727) Acquisition of treasury stock.......................... (15,791) - - ---------- ---------- ---------- Net cash flows from (used in) financing activities... 113,020 828,349 (634,902) ---------- ---------- ---------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..... 567 (60,214) 72,884 CASH AND CASH EQUIVALENTS: Beginning of the period................................ 16,394 76,608 3,724 ---------- ---------- ---------- End of the period...................................... $ 15,827 $ 16,394 $ 76,608 ========== ========== ========== The Notes to Consolidated Financial Statements are an integral part of this statement. 57
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CUMULATIVE PREFERRED AND PREFERENCE STOCK (Dollars in Thousands) December 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (Restated) ------------------------------------ CUMULATIVE PREFERRED AND PREFERENCE STOCK: Preferred stock not subject to mandatory redemption, Par value $100 per share, authorized 600,000 shares, Outstanding - 4 1/2% Series, 138,576 shares........................ $ 13,858 $ 13,858 $ 13,858 4 1/4% Series, 60,000 shares......................... 6,000 6,000 6,000 5% Series, 50,000 shares............................. 5,000 5,000 5,000 ---------- ---------- ---------- TOTAL CUMULATIVE PREFERRED STOCK............................. $ 24,858 $ 24,858 $ 24,858 ---------- ---------- ---------- Preference stock subject to mandatory redemption, Without par value, $100 stated value, authorized 4,000,000 shares, outstanding - 7.58% Series, 500,000 shares......................... - - $ 50,000 ---------- ---------- ---------- TOTAL CUMULATIVE PREFERRED AND PREFERENCE STOCK.............. $ 24,858 $ 24,858 $ 74,858 ========== ========== ========== The Notes to Consolidated Financial Statements are an integral part of this statement. 58
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands) Year Ended December 31, ------------------------------------- 1999 1998 1997 ----------- ---------- ---------- (Restated) ------------------------------------- CUMULATIVE PREFERRED AND PREFERENCE STOCK: Beginning balance.............................. $ 24,858 $ 74,858 $ 74,858 Redemption of preference stock................. - (50,000) - ----------- ----------- ----------- Ending balance................................. 24,858 24,858 74,858 ----------- ----------- ----------- COMMON STOCK: Beginning balance.............................. 329,548 327,048 323,126 Issuance of common stock....................... 11,960 2,500 3,922 ----------- ----------- ----------- Ending balance................................. 341,508 329,548 327,048 ----------- ----------- ----------- PAID-IN CAPITAL: Beginning balance.............................. 775,337 760,553 739,433 Expenses on common stock....................... - - (5) Issuance of common stock....................... 45,608 14,784 21,125 ----------- ----------- ----------- Ending balance................................. 820,945 775,337 760,553 ----------- ----------- ----------- RETAINED EARNINGS: Beginning balance.............................. 810,617 919,045 562,121 Net income..................................... 14,296 35,649 498,652 Dividends on preferred and preference stock.... (1,129) (3,591) (4,919) Dividends on common stock...................... (143,904) (140,486) (136,809) ----------- ----------- ----------- Ending balance................................. 679,880 810,617 919,045 ----------- ----------- ----------- ACCUMULATED OTHER COMPREHENSIVE INCOME: Beginning balance.............................. 9,508 12,119 - Unrealized (loss) gain on marketable securities.................................. 46,997 (3,215) 25,248 Unrealized loss on currency translation........ (115) (1,026) - Income tax benefit (expense)................... (18,602) 1,630 (13,129) ----------- ----------- ----------- Ending balance................................. 37,788 9,508 12,119 ----------- ----------- ----------- TREASURY STOCK: Beginning balance.............................. - - - Acquisition of treasury stock.................. (15,791) - - ----------- ----------- ----------- Ending balance................................. (15,791) - - ----------- ----------- ----------- TOTAL SHAREHOLDERS' EQUITY....................... $ 1,889,188 $ 1,949,868 $ 2,093,623 =========== =========== =========== The Notes to Consolidated Financial Statements are an integral part of this statement. 59
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 628,000 customers in Kansas and providing monitored services to approximately 1.6 million customers in North America, the United Kingdom and continental Europe. 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. 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. Our investments in Protection One and ONEOK are owned by Westar Capital, Inc. (Westar Capital), a wholly-owned subsidiary. Principles of Consolidation: The company prepares its financial statements in conformity with accounting principles generally accepted in the United States. 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. Use of Management's Estimates: The preparation of financial statements require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Consolidated Statements of Cash Flows: For purposes of the Consolidated Statements of Cash Flows, the company considers highly liquid collateralized debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash paid for interest and income taxes for each of the years ended December 31, are as follows: 1999 1998 1997 -------- -------- -------- (Dollars in Thousands) Interest on financing activities (net of amount capitalized)............... $298,802 $220,848 $193,468 Income taxes................................ 784 47,196 404,548 60
During 1997, the company contributed the net assets of its natural gas business totaling approximately $594 million to ONEOK in exchange for an ownership interest of 45% in ONEOK. Available-for-sale Securities: The company classifies marketable equity and debt securities accounted for under the cost method as available-for-sale. These securities are reported at fair value based on quoted market prices. Cumulative, temporary unrealized gains and losses, net of the related tax effect, are reported as a separate component of shareholders' equity until realized. Current temporary changes in unrealized gains and losses are reported as a component of other comprehensive income. The following table summarizes the company's investments in marketable securities as of December 31: Gross Unrealized ---------------------------------------- Cost Gains Losses Fair Value -------- ------- --------- ---------- 1999: (Dollars in Thousands) Equity securities................................................ $ 43,124 $70,407 $ (1,628) $111,903 Debt securities.................................................. 65,225 - - 65,225 -------- ------- -------- -------- Total.......................................................... $108,349 $70,407 $ (1,628) $177,128 ======== ======= ======== ======== 1998: Equity securities................................................ $ 94,369 $45,685 $(10,182) $129,872 Debt securities.................................................. 172,129 - (13,924) 158,205 -------- ------- -------- -------- Total.......................................................... $266,498 $45,685 $(24,106) $288,077 ======== ======= ======== ======== 1997: Equity securities................................................. $ 50,010 $25,248 $ - $ 75,258 Debt securities................................................... - - - - ------- ------ ------- ------- Total........................................................... $ 50,010 $25,248 $ - $ 75,258 ======== ======= ======== ======== Proceeds from the sales of equity and debt securities were $73.5 million, $27.9 million, and $1,533.5 million in 1999, 1998 and 1997, respectively. In 1997, the only available-for-sale security sold was an investment in Tyco International common stock (See Note 19 of Notes to Consolidated Financial Statements). The gross realized gains from sales of equity and debt investments were $12.6 million in 1999 and $2.0 million in 1998. The gross realized losses from sales of equity and debt investments were $38.8 million in 1999 and $16.1 million in 1998. 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 1999, 6.00% in 1998 and 5.80% in 1997. 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, the original cost and removal cost, less salvage value, are charged to accumulated depreciation. In accordance with regulatory decisions made by the Kansas Corporation Commission (KCC), the acquisition premium of approximately $801 million resulting from the acquisition of KGE in 1992 is being amortized over 40 years. The acquisition premium is classified as electric plant in service. Accumulated amortization totaled $88.1 million as of December 31, 1999, and $68 61
million as of December 31, 1998. 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 2.92% during 1999, 2.88% during 1998 and 2.89% during 1997. Nonutility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. Inventories and Supplies: Inventories and supplies for the company's utility business are stated at average cost. Inventories, comprised of alarm systems and parts, are stated at the lower of average cost or market. Nuclear Fuel: 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 was $29.3 million at December 31, 1999, $39.5 million at December 31, 1998 and $20.9 million at December 31, 1997. 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. Protection One historically amortized the costs it allocated to its customer accounts by using the straight-line method over a ten-year life, except for accounts acquired from Westinghouse for which an eight-year 120% declining balance method has been applied. The straight-line method, indicated in Accounting Principles Board Opinion No. 17 as the appropriate method for such assets, has been the predominant method used to amortize customer accounts in the monitored services industry. Protection One's management is not aware of whether the economic life or the rate of realization for Protection One's customer accounts differ materially from other monitored services companies. The choice of a ten-year life was based on Protection One's estimates and judgments about the amounts and timing of expected future revenues from these assets, the rate of attrition of such revenue over customer life, and average customer account life. Ten years was used because, in Protection One's opinion, it would adequately match amortization cost with anticipated revenue from those assets even though many accounts were expected to produce revenue over periods substantially longer than ten years. Effectively, it expensed the asset ratably over an "expected average customer life" that was shorter than the expected life of the revenue stream, thus implicitly giving recognition to projected revenues for a period beyond ten years. Protection One conducted a comprehensive review of its amortization policy during the third quarter of 1999. This review was performed specifically to evaluate the historic amortization policy in light of the inherent declining revenue curve over the life of a pool of customer accounts and Protection One's historical attrition experience. After completing the review, Protection One identified three distinct pools, each of which has distinct attributes that affect differing attrition characteristics. The pools correspond to Protection One's North America, Multifamily and Europe business segments. For the North America and Europe pools, the analyzed data indicated that Protection One can expect attrition to be greatest in years one through five of asset life and that a change from a straight-line to a declining balance (accelerated) method would more closely match future amortization cost with the 62
estimated revenue stream from these assets. Protection One has elected to change to that method except for accounts acquired in the Westinghouse acquisition which are utilizing an accelerated method. See Note 2 of the Notes to Consolidated Financial Statements for additional information. No change was made in the method used for the Multifamily pool. Protection One's amortization rates consider the average estimated remaining life and historical and projected attrition rates. The amortization method for each customer pool is as follows: Pool Method ---------------------------------------------------------------- North America Acquired Westinghouse customers Eight-year 120% declining balance Other Ten-year 130% declining balance Europe Ten-year 125% declining balance Multifamily Ten-year straight-line Adoption of the declining balance method effectively shortens the estimated expected average customer life for these two customer pools, and does so in a way that does not make it possible to distinguish the effect of a change in method (straight-line to declining balance) from the change in estimated lives. In such cases, generally accepted accounting principles require that the effect of such a change be recognized in operations in the period of the change, rather than as a cumulative effect of a change in accounting principle. Protection One changed to the declining balance method in the third quarter of 1999 for Europe customers and most of North America customers which had been amortized on a straight-line basis. Accordingly, the effect of the change in accounting principle increased Protection One's amortization expense reported in the third quarter of 1999 by $47 million. Protection One's accumulated amortization recorded on its balance sheet would have been approximately $34 million higher, through the end of the second quarter of 1999, if it had historically used the declining balance method. In accordance with SFAS No. 121, "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to Be Disposed Of", long-lived assets held and used by Protection One are evaluated for recoverability on a periodic basis or as circumstances warrant. An impairment would be recognized when the undiscounted expected future operating cash flows by customer pool derived from customer accounts is less than the carrying value of capitalized customer accounts and goodwill. Due to the high level of customer attrition experienced in 1999 and the decline in market value of Protection One's publicly traded equity and debt securities, Protection One performed an impairment test on its customer account asset in the fourth quarter and concluded that no impairment has occurred. Protection One also reevaluated its amortization estimates and concluded no change was needed. Goodwill: Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One. Protection One has historically amortized goodwill on a straight-line basis over 40 years. The carrying value of goodwill was included in Protection One's evaluation of recoverability of customer accounts. No reduction in the carrying value was necessary at December 31, 1999. In conjunction with the impairment test for customer accounts, Protection One re- 63
evaluated the original assumptions and rationale utilized in the establishment of the carrying value and estimated useful life of goodwill. Protection One concluded that due to continued losses and increased levels of attrition experienced in 1999, the estimated useful life of goodwill should be reduced from 40 years to 20 years. As of January 1, 2000, the remaining goodwill, net of accumulated amortization, will be amortized over its remaining useful life based on a 20-year life. On Protection One's existing account base, Protection One anticipates that this will result in an increase in annual goodwill amortization of approximately $32.6 million prospectively. Accumulated amortization was $59.1 million, $29.0 million and $6.0 million at December 31, 1999, 1998 and 1997. 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, 1999 1998 1997 - ------------------------------------------------------------------------- (Dollars in Thousands) Recoverable taxes........................ $218,239 $205,416 $212,996 Debt issuance costs...................... 68,239 73,635 75,336 Deferred employee benefit costs.......... 36,251 36,128 37,875 Deferred plant costs..................... 30,306 30,657 30,979 Coal contract settlement costs........... 7,957 12,259 16,032 Other regulatory assets.................. 5,012 6,118 7,203 -------- -------- -------- Total regulatory assets................ $366,004 $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. 64
The company expects to recover all of the above regulatory assets in rates charged to customers. A return is allowed on deferred plant costs and coal contract settlement costs and approximately $49.1 million of debt issuance costs. Minority Interests: Minority interests represent the minority shareholders' proportionate share of the shareholders' equity and net loss 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 $44 million at December 31, 1999,$38.8 million at December 31, 1998, and $36.7 million at December 31, 1997, are recorded as a component of accounts receivable (net) on the Consolidated Balance Sheets. Monitored services sales are recognized when monitoring, extended service protection, patrol, repair and other services are provided. Deferred revenues result from customers who are billed for monitoring, extended service protection and patrol and alarm response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. The company's allowance for doubtful accounts receivable totaled $35.8 million at December 31, 1999, $29.5 million at December 31, 1998, and $8.4 million at December 31, 1997. 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. The company has a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for tax benefits utilized in the company's consolidated tax return. 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. The change in market value of these energy trading contracts is recorded on the Consolidated Balance Sheet, and included in earnings. The company is also exposed to commodity price changes outside of trading activities. The company uses derivatives for non-trading purposes primarily to reduce exposure relative to the volatility of cash market prices. The company currently records the change in market value of these cash flow hedges on its Consolidated Balance Sheet. The company does not recognize gains and losses in net income until the period these options and forwards are settled. The company has considered a number of risks and costs associated with the future contractual commitments included in the company's energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks which management policy dictates. The counterparties in the company's portfolio are primarily large energy marketers and major utility companies. The 65
creditworthiness of the company's counterparties could positively or negatively impact the company's overall exposure to credit risk. The company maintains credit policies with regard to its counterparties that, in management's view, minimize overall credit risk. 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: 1999 1998 1997 -------- -------- -------- (Dollars in Millions) Cash surrender value of policies (1).. $ 642.4 $ 587.5 $ 547.7 Borrowings against policies........... (608.3) (558.5) (524.3) ------- ------- ------- COLI (net)............................ $ 34.1 $ 29.0 $ 23.4 ======= ======= ======= (1) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 1999, 1998 and 1997. Income was recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as other income approximated $1.4 million in 1999, $13.7 million in 1998 and $0.6 in 1997. New Pronouncements: In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). In June 1999, the FASB issued Statement No. 137 "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in hybrid contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. With respect to hybrid contracts, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid contracts that were issued, acquired, or substantively modified after December 31, 1998. SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met and that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, in part, allows special hedge accounting for fair value and cash flow hedges. The company had no fair value hedges as of December 31, 1999. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. If SFAS 133 were required to be applied to cash flow hedges in place at December 31, 1999, changes in the fair value of options and forwards would contribute approximately $1.3 million of additional loss to other comprehensive income for the twelve months ended December 31, 1999, if these hedges were 100% effective. The company is 66
still in the process of evaluating the effectiveness of these hedges. SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000. SFAS 133 cannot be applied retroactively. The company is currently evaluating commodity contracts and financial instruments to determine what, if any, effect of adopting SFAS 133 might have on its financial statements. The company has not yet quantified all effects of adopting SFAS 133 on its financial statements; however, SFAS 133 could increase volatility in earnings and other comprehensive income. The company plans to adopt SFAS 133 as of January 1, 2001. On January 1, 1999, the company adopted Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF Issue 98-10). 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. Reclassifications: Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 2. RESTATEMENT OF FINANCIAL STATEMENTS Following extensive conversations between Protection One and the staff of the SEC, which have previously been disclosed, the company has restated its Consolidated Financial Statements as of December 31, 1999, 1998 and 1997 and for the years then ended and for each of the periods ended March 31, June 30, and September 30, 2000, to reflect restatements undertaken by Protection One. This restatement primarily relates to the amortization of customer accounts acquired and amounts allocated to obligations assumed in the Westinghouse Security Systems (WSS) acquisition. A description of the principal adjustments which comprise the restatement is as follows: The first adjustment reflects a change in the historical amortization expense recorded for customer accounts acquired in the WSS acquisition. The life of the acquired WSS customers was initially estimated at ten years. Straight-line amortization had originally been implemented. With the restatement, an eight-year estimated life and an accelerated amortization method will be used for customers acquired from WSS as of the acquisition date. The second adjustment reverses a special charge of $12.75 million for excess customer attrition that was recorded in the fourth quarter of 1997. This charge had been recorded for attrition experienced in the WSS customer account base in 1997. The third adjustment reduces a repurchase obligation (SAMCO contract financing) to more closely match the estimated fair value of the obligation to the estimated fair value of WSS customer accounts on a per account basis. This change in valuation has the effect of reducing the obligation and goodwill and eliminating $14.8 million of a non-recurring $16.3 million pre-tax gain that was reported in 1998 when this obligation was repaid. The fourth adjustment reduces goodwill as a result of a purchase price adjustment related to the WSS acquisition. Goodwill has been reduced by the amount of the claim of $33.8 million. A receivable had not originally been recorded for this claim. The change was made to establish this receivable which reduces recorded goodwill. Westar Industries, formerly Westar Capital, entered into a comprehensive settlement agreement with Westinghouse in November 2000 and 67
received $37.5 million. A summary of the significant effects of the restatement is as follows: Restatement Adjustments --------------------------------------------------------- WSS SAMCO WSS As Previously Accelerated Special Repurchase Goodwill Reported Amortization Charge Obligation Reduction As Restated ------------- ------------ --------- ---------- --------- ----------- At December 31, 1999 - -------------------- Customer accounts, net.......... $ 1,138,902 $ (19,720) $ 12,750 $ - $ - $ 1,131,932 Goodwill, net................... 1,102,157 - - (13,877) (31,239) 1,057,041 Other assets.................... 318,622 - - - 33,772 352,394 Deferred income taxes and investment tax credits......... 982,548 (6,903) 4,462 (4,858) 886 976,135 Minority interests.............. 193,499 (883) 1,450 (1,514) 182 192,734 Retained earnings............... 691,016 (11,931) 6,837 (7,507) 1,465 679,880 For the year-ended December 31, 1999 - ------------------------------------ Depreciation and amortization................... $ 407,007 $ (2,122) $ - $ (371) $ (845) $ 403,669 Minority interests.............. 12,934 (212) - (37) (85) 12,600 Income tax expense (benefit).... (33,364) 742 - 130 295 (32,197) Net income (loss) before extraordinary gain............. 717 1,169 - 204 464 2,554 Earnings available for common stock................... 11,330 1,169 - 204 464 13,167 Earnings per average common share outstanding.............. $ 0.17 $ 0.02 - - $ 0.01 $ 0.20 Restatement Adjustments --------------------------------------------------------- WSS SAMCO WSS As Previously Accelerated Special Repurchase Goodwill Reported Amortization Charge Obligation Reduction As Restated ------------- ------------ --------- ---------- --------- ----------- At December 31, 1998 - -------------------- Customer accounts, net.......... $ 1,014,428 $ (21,842) $ 12,750 $ - $ - $ 1,005,336 Goodwill, net................... 1,188,253 - - (14,248) (32,084) 1,141,921 Other assets.................... 293,995 - - - 33,772 327,767 Deferred income taxes and investment tax credits......... 938,659 (7,645) 4,462 (4,988) 591 931,079 Minority interests.............. 205,822 (1,095) 1,450 (1,551) 97 204,723 Retained earnings............... 823,590 (13,099) 6,837 (7,711) 1,000 810,617 For the year-ended December 31, 1998 - ------------------------------------ Depreciation and amortization................... $ 280,673 $ 8,668 $ - $ (372) $ (844) $ 288,125 Minority interests.............. 382 915 - 1,554 (89) 2,762 Other income.................... 6,274 - - (14,837) - (8,563) Income tax expense (benefit).... 14,557 (3,033) - (5,064) 295 6,755 Net income (loss) before extraordinary gain............. 46,165 (4,718) - (7,849) 460 34,058 Earnings available for common stock................... 44,165 (4,718) - (7,849) 460 32,058 Earnings per average common share outstanding.............. $ 0.67 $ (0.08) - $ (0.12) $ 0.01 $ 0.48 Restatement Adjustments --------------------------------------------------------- WSS SAMCO WSS As Previously Accelerated Special Repurchase Goodwill Reported Amortization Charge Obligation Reduction As Restated ------------- ------------ --------- ---------- --------- ----------- 68
At December 31, 1997 - -------------------- Customer accounts, net....... $ 541,146 $ (13,174) $ 12,750 $ - $ - $ 540,722 Goodwill, net................ 844,759 - - (14,620) (32,928) 797,211 Other assets................. 221,700 - - - 33,772 255,472 Current maturities of long-term debt.............. 21,217 - - 1,308 - 22,525 Long-term debt, net.......... 2,188,034 - - (16,145) - 2,171,889 Deferred income taxes and investment tax credits...... 1,069,907 (4,612) 4,462 76 296 1,070,129 Minority interests........... 165,530 (179) 1,450 2 8 166,811 Retained earnings............ 919,911 (8,383) 6,837 139 541 919,045 For the year-ended December 31, 1997 - ------------------------------------ Depreciation and amortization................ $ 256,725 $ 13,174 $ - $ (217) $ (844) $ 268,838 Monitored services special charge...................... 24,292 - (12,750) - - 11,542 Minority interests........... 3,586 179 (1,450) (2) (8) 2,305 Income tax expense (benefit). 382,987 (4,612) 4,462 76 296 383,209 Net income (loss) before extraordinary gain.......... 499,518 (8,383) 6,837 139 541 498,652 Earnings available for common stock................ 494,599 (8,383) 6,837 139 541 493,733 Earnings per average common share outstanding........... $ 7.59 $ (0.13) $ 0.11 $ - $ 0.01 $ 7.58 The net effect of adjustments made to 1999, 1998 and 1997 quarterly reported results is disclosed in Note 24. Prior to this restatement, during the third quarter of 1999, Protection One changed its amortization method for its customer account intangible assets from a straight-line to an accelerated method to more closely match future amortization expense with the estimated revenue stream from these assets. The effect of the change in accounting principle increased amortization expense reported in the third quarter of 1999 by $47 million. The change in the WSS customer account amortization method restates the results of 1997, 1998 and 1999 and thereby reduces the cumulative charge recorded in the third quarter of 1999. 3. MONITORED SERVICES BUSINESS Protection One acquired a significant number of security companies in 1998 and 1997. The largest acquisitions included Protection One in November 1997, Network Multifamily, Inc. (Multifamily) in January 1998, Multimedia Security Services, Inc. in March 1998, and Compagnie Europeenne de Telesecurite (CET) in October 1998. All companies acquired have been accounted for using the purchase method. The principal assets acquired in the acquisitions are customer accounts. The excess of the purchase price over the estimated fair value of the net assets acquired is recorded as goodwill. The results of operations of each acquisition have been included in the consolidated results of operations of Protection One from the date of the acquisition. 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 and 1997 occurred as of January 1, 1997. Year Ended December 31, 1998 1997 ---------- ---------- (Unaudited) 69
(Dollars in Thousands, Except Per Share Data) Sales.................................. $2,175,089 $2,462,849 Earnings available for common stock.... 21,449 462,398 Earnings per share..................... $ 0.33 $ 7.10 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. During 1999, Protection One completed four acquisitions, all in the United Kingdom, for a combined purchase price of approximately $32 million. Protection One's purchase price allocations for the 1999 acquisitions are preliminary and may be adjusted as additional information is obtained. During the third quarter of 1999, Protection One sold the assets which comprised its Mobile Services Group. Cash proceeds of this sale approximated $20 million and Protection One recorded a pre-tax gain of approximately $17.3 million. In December 1997, Protection One incurred a charge of $11.5 million for costs associated with the closing of business activities that were no longer of continuing value to the combined operations. 4. MARKETABLE SECURITIES During the fourth quarter of 1999, the company decided to sell its remaining marketable security investments in paging industry companies. These securities have been classified as available-for-sale; therefore, changes in market value have been historically reported as a component of other comprehensive income. The market value for these securities declined during the last six to nine months of 1999. The company determined that the decline in value of these securities was other than temporary and a charge to earnings for the decline in value was required at December 31, 1999. Therefore, the company recorded a non-cash charge of $76.2 million in the fourth quarter of 1999. This charge to earnings has been presented separately in the accompanying Consolidated Statements of Income. See also Note 25 for subsequent events. 5. CUSTOMER ACCOUNTS The following is a rollforward of the investment in customer accounts (at cost) for the following years: December 31, 1999 1998 1997 ---------- ---------- -------- Beginning customer accounts, net..... $1,005,336 $ 540,722 $265,530 Acquisition of customer accounts..... 350,723 571,229 319,481 Amortization of customer accounts.... (187,092) (97,089) (44,240) 70
Non-cash charges against purchase holdbacks and other....... (37,035) (9,526) (49) ---------- ---------- -------- Ending customer accounts, net........ $1,131,932 $1,005,336 $540,722 ========== ========== ======== Accumulated amortization of the investment in customer accounts at December 31, 1999, 1998 and 1997 was $330.7 million, $139.8 million and $43.1 million, respectively. In conjunction with certain purchases of customer accounts, Protection One withholds a portion of the purchase price as a reserve to offset qualifying losses of the acquired customer accounts for a specified period as provided for in the purchase agreements, and as a reserve for purchase price settlements of assets acquired and liabilities assumed. The estimated expected amount to be paid at the end of the holdback period is capitalized and an equivalent current liability established at the time of purchase. The following is a rollforward of purchase holdbacks at December 31: 1999 1998 1997 ------- ------- ------- Balance, beginning of year......... $42,303 $11,444 $ 146 Additions.......................... 26,663 72,673 11,979 Non-cash charges against customer accounts................ (37,035) (9,526) (341) Cash payments to sellers........... (11,718) (32,288) (340) ------- ------- ------- Balance, end of year............... $20,213 $42,303 $11,444 ======= ======= ======= Purchase holdback periods are negotiated between Protection One and sellers or dealers, but typically range from zero to 12 months. At the end of the period prescribed by the purchase holdback, Protection One verifies customer losses experienced during the period and calculates a final payment to the seller or dealer. The purchase holdback is extinguished at the time of final payment and a corresponding adjustment is made in the customer intangible to the extent the final payment varies from the estimated liability established at the time of purchase. 6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at December 31: 1999 1998 1997 ---------- ---------- ---------- (Dollars in Thousands) Electric plant in service............ $5,769,401 $5,646,176 $5,564,695 Less - accumulated depreciation...... 2,141,037 2,015,880 1,895,084 ---------- ---------- ---------- 3,628,364 3,630,296 3,669,611 Construction work in progress........ 170,061 82,700 60,006 Nuclear fuel (net)................... 28,013 39,497 40,696 ---------- ---------- ---------- Net utility plant.................. 3,826,438 3,752,493 3,770,313 Non-utility plant in service......... 92,872 62,324 20,237 Less - accumulated depreciation...... 29,866 14,901 4,022 ---------- ---------- ---------- Net property, plant and equipment.. $3,889,444 $3,799,916 $3,786,528 ========== ========== ========== 71
7. JOINT OWNERSHIP OF UTILITY PLANTS Company's Ownership at December 31, 1999 --------------------------------------------------- In-Service Invest- Accumulated Net Per- Dates ment Depreciation (MW) cent ---------- ---------- ------------ ----- ---- (Dollars in Thousands) La Cygne 1 (a) Jun 1973 $ 174,450 $ 113,415 344.0 50 Jeffrey 1 (b) Jul 1978 302,452 138,934 625.0 84 Jeffrey 2 (b) May 1980 294,502 128,865 622.0 84 Jeffrey 3 (b) May 1983 407,864 166,298 623.0 84 Jeffrey wind 1 (b) May 1999 855 17 0.5 84 Jeffrey wind 2 (b) May 1999 854 16 0.5 84 Wolf Creek (c) Sep 1985 1,378,238 460,880 550.0 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 337 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. 8. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD The company's investments which are accounted for by the equity method are as follows: Equity Earnings, Ownership at Investment at Year Ended December 31, December 31, December 31, ---------------------------- ---------------------- 1999 1999 1998 1997 1999 1998 1997 ------------ -------- -------- -------- ------ ------ ------ (Dollars in Thousands) ONEOK, Inc. (1)........... 45% $590,109 $615,094 $596,206 $6,945 $6,064 $1,970 Affordable Housing Tax Credit limited partnerships (2)......... 13% to 29% 79,460 85,461 51,571 - - - Paradigm Direct........... 40% 35,385 - - 1,254 - - International companies and joint ventures (3)... 9% to 50% 18,724 10,500 16,299 - - - Other..................... - - 3,312 - (672) - (1) The company also received approximately $41 million of preferred and common dividends in 1999. (2) Investment is aggregated. Individual investments are not material. Based on an order received by the KCC, equity earnings from these investments are used to offset costs associated with postretirement and postemployment benefits offered to the company's 72
employees. (3) Investment is aggregated. Individual investments are not material. During 1998, the company recognized an other than temporary decline in value of its foreign equity investments as discussed in Note 17. The following summarized financial information for the company's investment in ONEOK is presented as of and for the periods ended December 31, 1999, and November 30, 1998, the most recent periods for which public information is available. December 31, November 30, 1999 1998 -------------------------------------------------------- (Dollars in Thousands) Balance Sheet: Current assets ......... $ 593,721 $ 404,358 Non-current assets...... 2,645,854 2,091,797 Current liabilities..... 786,713 338,466 Non-current liabilities. 1,301,338 993,668 Equity.................. 1,151,524 1,164,021 December 31, November 30, Twelve Months Ended 1999 1998 -------------------------------------------------------- (Dollars in Thousands) Income Statement: Revenues................ $2,070,983 $1,896,178 Gross profit............ 760,209 645,606 Net income.............. 106,873 103,525 At December 31, 1999, the company's ownership interest in ONEOK is comprised of approximately 2.3 million common shares and approximately 19.9 million convertible preferred shares. If all the preferred shares were converted, the company would own approximately 45% of ONEOK's common shares presently outstanding. 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 $1.1 billion. 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, which is used 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, 1999 1998 1997 ----------------------------------------------------------------------- (Dollars in Thousands) Borrowings outstanding at year end: Credit agreement................. $ 50,000 $ - $ - 73
Bank loans....................... 120,000 164,700 161,000 Commercial paper notes........... 535,421 147,772 75,500 ---------- -------- -------- Total.......................... $ 705,421 $312,472 236,500 ========== ======== ======== Weighted average interest rate on debt outstanding at year end (including fees)................. 6.96% 5.94% 6.28% Weighted average short-term debt outstanding during the year...... $ 455,184 $529,255 $787,507 Weighted daily average interest rates during the year (including fees)................. 5.76% 5.93% 5.93% Unused lines of credit supporting commercial paper notes........... $1,021,000 $820,900 $772,850 The company borrowed $225 million in short-term debt in 1999 to fund Westar Capital's revolving credit agreement to Protection One. The company's interest expense on short-term debt was $57.7 million in 1999, $55.3 million in 1998 and $73.8 million in 1997. The unsecured short-term lines of credit included three revolving credit facilities with various banks as follows: Amount Facility Termination Date --------------------------------------------------- $300 million 364-day March 15, 2000 500 million 5-year March 17, 2003 250 million 6 1/2-month June 30, 2000 In March 2000, the company amended the $300 million facility to reduce the commitment to $242 million and to extend the maturity date to June 30, 2000. The company also amended all of these credit facilities to reflect the possibility of borrowing from them rather than using them to provide support for commercial paper borrowings. Amendments to the credit facilities include increased pricing to reflect credit quality and the potential drawn nature of credit facilities rather than support for commercial paper, redefinition of the total debt to capital financial covenant, limitation on use of proceeds from sale of first mortgage bonds to pay off debt outstanding under the credit facilities before proceeds may be used for other purposes, and a commitment to use the company's "best efforts" to pledge first mortgage bonds to support its credit facilities if our senior unsecured credit rating drops below "investment grade" (bonds rated below BBB by S&P and Fitch and below Baa by Moody's as determined by Standard & Poor's Ratings Group (S&P) and Moody's Investors Service (Moody's). 74
10. LONG-TERM DEBT Long-term debt outstanding is as follows at December 31: 1999 1998 1997 ---------- ---------- ---------- (Dollars in Thousands) (Restated - Note 2) -------------------------------------- Western Resources First mortgage bond series: 7 1/4% due 1999 ................... $ - $ 125,000 $ 125,000 8 7/8% due 2000 ................... 75,000 75,000 75,000 7 1/4% due 2002 ................... 100,000 100,000 100,000 8 1/2% due 2022 ................... 125,000 125,000 125,000 7.65% due 2023. ................... 100,000 100,000 100,000 ---------- ---------- ---------- 400,000 525,000 525,000 ---------- ---------- ---------- Pollution control bond series: Variable due 2032, 4.80% at December 31, 1999 ............... 45,000 45,000 45,000 Variable due 2032, 4.54% at December 31, 1999 ............... 30,500 30,500 30,500 6% due 2033 ....................... 58,420 58,420 58,420 ---------- ---------- ---------- 133,920 133,920 133,920 ---------- ---------- ---------- KGE First mortgage bond series: 7.60% due 2003. ................... 135,000 135,000 135,000 6 1/2% due 2005 ................... 65,000 65,000 65,000 6.20% due 2006. ................... 100,000 100,000 100,000 ---------- ---------- ---------- 300,000 300,000 300,000 ---------- ---------- ---------- Pollution control bond series: 5.10% due 2023. ................... 13,653 13,673 13,757 Variable due 2027, 4.25% at December 31, 1999 ............... 21,940 21,940 21,940 7.0% due 2031 ..................... 327,500 327,500 327,500 Variable due 2032, 4.199% at December 31, 1999 ............... 14,500 14,500 14,500 Variable due 2032, 4.30% at December 31, 1999 ............... 10,000 10,000 10,000 ---------- ---------- ---------- 387,593 387,613 387,697 ---------- ---------- ---------- Western Resources 6 7/8% unsecured senior notes due 2004. ....................... 370,000 370,000 370,000 7 1/8% unsecured senior notes due 2009. ....................... 150,000 150,000 150,000 6.80% unsecured senior notes due 2018. . ..................... 29,783 29,985 - 75
6.25% unsecured senior notes due 2018, putable/callable 2003...... 400,000 400,000 - ---------- ---------- ---------- 949,783 949,985 520,000 ---------- ---------- ---------- Protection One Senior credit facility due 2001, 6.8% at December 31, 1998 ....... - 42,417 - Convertible senior subordinated notes due 2003, fixed rate 6.75%. 53,950 53,950 102,500 Senior subordinated discount notes due 2005, effective rate of 6.4%. 87,038 125,590 171,926 Senior unsecured notes due 2005, fixed rate 7.375% ............... 250,000 250,000 - Senior subordinated notes due 2009, fixed rate 8.125% ............... 341,415 350,000 - CET recourse financing agreements, average effective rate 18% and 15%, respectively ............. 60,838 93,541 - Other ............................. 2,033 2,574 - Customer repurchase agreement, due 1998. ....................... - - 54,292 ---------- ---------- ---------- 795,274 918,072 328,718 ---------- ---------- ---------- Other long-term agreements........... 21,895 8,325 4,798 Unamortized debt premium............. 13,726 13,918 - Less: Unamortized debt discount............ (7,458) (7,931) (5,719) Long-term debt due within one year... (111,667) (165,838) (22,525) ---------- ---------- ---------- Long-term debt (net)................. $2,883,066 $3,063,064 $2,171,889 ========== ========== ========== Debt discount and expenses are being amortized over the remaining lives of each issue. 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. 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 the first mortgage bonds. The notes are structurally subordinated to all secured and unsecured debt of the company's subsidiaries. In December 1998, Protection One entered into a revolving credit facility which provided for borrowings of up to $500 million, subsequently decreased to $250 million, and was to expire in December 2001. As a result of Protection One not meeting its debt covenants under this facility, in December 1999, Westar Capital acquired the debt and assumed the lenders' obligations. In 1998, Protection One issued $350 million of Unsecured Senior Subordinated Notes. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price. 76
Protection One did not complete a required exchange offer during 1999. As a result, the interest rate on this facility increased to 8.625% in June 1999. If the exchange offer is completed, the interest rate will revert back to 8.125%. Interest on this facility is payable semi-annually on January 15 and July 15. In 1998, Protection One issued $250 million of Senior Unsecured Notes. Interest is payable semi-annually on February 15 and August 15. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price. In 1995, Protection One issued $166 million of Unsecured Senior Subordinated Discount Notes with a fixed interest rate of 13 5/8%. Interest payments began in 1999 and are payable semi-annually on June 30 and December 31. In connection with the acquisition of Protection One in 1997, these notes were restated to fair value reflecting a current market yield of approximately 6.4%. This resulted in bond premium being recorded to reflect the increase in value of the notes as a result of the decline in interest rates since the note issuance. The revaluation has no impact on the expected cash flow to existing noteholders. In 1998, Protection One redeemed notes with a book value of $69.4 million and recorded an extraordinary gain on the extinguishment of $1.6 million, net of tax. The remaining notes are redeemable at Protection One's option in whole or in part, at anytime on or after June 30, 2000, at a predefined price. In 1996, Protection One issued $103.5 million of Convertible Senior Subordinated Notes. Interest is payable semi-annually on March 15 and September 15. The notes are convertible at any time at a conversion price of $11.19 per share. The notes are redeemable, at Protection One's option, at a specified redemption price, beginning September 19, 1999. Protection One's subsidiary CET has recognized as a financing transaction cash received through the sale of security equipment and future cash flows to be received under security equipment operating lease agreements with customers to a third-party financing company. A liability has been recorded for the proceeds of these sales as the finance company has recourse to CET in the event of nonpayment by customers of their equipment rental obligations. The average implicit interest rate in the financing is 18% at December 31, 1999. Accordingly, the liability is reduced, rental revenue is recognized, and interest expense is being recorded as these recourse obligations are reduced through the cash receipts paid to the financing company over the term of the related equipment rental agreements which averages four years. The liability is increased as new security monitoring equipment and equipment rental agreements are sold to the finance company that have recourse provisions. Protection One's debt instruments contain financial and operating covenants which may restrict its ability to incur additional debt, pay dividends, make loans or advances and sell assets. From September 30, 1999 through December 31, 1999, Protection One received waivers from compliance with the then-applicable leverage and interest coverage ratio covenants under the senior credit facility. At December 31, 1999 Protection One was in compliance with all financial covenants governing its debt securities. The indentures governing Protection One's debt securities require that Protection One offer to repurchase the securities in certain circumstances following a change of control. 77
In the fourth quarter 1999, Westar Capital purchased Protection One bonds on the open market at amounts less than the carrying amount of the debt. The company has recognized an extraordinary gain of $13.4 million, net of tax, at December 31, 1999 related to the retirement of this debt. Maturities of long-term debt through 2004 are as follows: Principal Year Amount ----------------------------- (Dollars in Thousands) 2000 ............... $111,667 2001 ............... 32,246 2002 ............... 106,472 2003 ............... 240,568 2004 ............... 370,457 The company's interest expense on long-term debt was $236.4 million in 1999, $170.9 million in 1998 and $120 million in 1997. 11. 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: Pension Benefits Postretirement Benefits -------------------------- ------------------------------ December 31, 1999 1998 1997 1999 1998 1997 --------------------------------------------------------------------------------------------------------- (Dollars in Thousands) Change in Benefit Obligation: Benefit obligation, beginning of year. $392,057 $462,964 $483,862 $ 87,519 $ 83,673 $122,993 Service cost ......................... 8,949 7,952 11,337 1,609 1,405 2,102 Interest cost......................... 26,487 31,278 35,836 5,854 5,763 9,098 Plan participants' contributions...... - - - 784 858 1,122 Benefits paid......................... (21,961) (24,682) (27,764) (6,990) (5,630) (10,167) Assumption changes.................... (49,499) 36,268 (19,184) (9,458) 6,801 - Actuarial losses (gains).............. (4,608) 10,095 (1,532) (31) (5,351) 4,421 Acquisitions.......................... (676) - - - - - Plan amendments....................... - - 6,866 - - - Curtailments, settlements and special term benefits (1).................... - (131,818) (26,457) - - (45,896) -------- -------- -------- -------- -------- -------- Benefit obligation, end of year....... $350,749 $392,057 $462,964 $ 79,287 $ 87,519 $ 83,673 ======== ======== ======== ======== ======== ======== Change in Plan Assets: Fair value of plan assets, beginning of year.................... $441,531 $584,792 $496,206 $ 173 $ 118 $ 78 Actual return on plan assets.......... 85,079 66,106 113,235 10 6 3 Acquisitions.......................... - - - - - - 78
Employer contribution................. 2,882 2,197 2,220 6,284 5,679 10,204 Plan participants' contributions...... - - - 784 - - Benefits paid......................... (22,497) (23,910) (26,869) (6,990) (5,630) (10,167) Settlements (1)....................... - (187,654) - - - - -------- -------- -------- -------- -------- -------- Fair value of plan assets, end of year.......................... $506,995 $441,531 $584,792 $ 261 $ 173 $ 118 ======== ======== ======== ======== ======== ======== Funded status......................... $156,246 $ 49,474 $121,828 $(79,026) $(87,346) $(83,555) Unrecognized net (gain)/loss.......... (205,338) (104,023) (193,313) (7,733) 1,814 (828) Unrecognized transition obligation, net..................... 209 244 (369) 52,171 56,159 60,146 Unrecognized prior service cost....... 32,854 36,309 39,763 (3,730) (4,131) (4,592) -------- -------- -------- -------- -------- -------- Accrued postretirement benefit costs.. $(16,029) $(17,996) $(32,091) $(38,318) $(33,504) $(28,829) ======== ======== ======== ======== ======== ======== Actuarial Assumptions: Discount rate......................... 7.75% 6.75% 7.5% 7.75% 6.75% 7.5% Expected rate of return............... 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% Compensation increase rate............ 4.5% 4.75% 4.75% 4.5% 4.75% 4.75% Components of net periodic benefit cost: Service cost.......................... $ 8,949 $ 7,952 $ 11,337 $ 1,610 $ 1,405 $ 2,102 Interest cost......................... 26,487 31,278 35,836 5,854 5,763 9,098 Expected return on plan assets........ (34,393) (39,069) (39,556) (16) (11) (4) Amortization of unrecognized transition obligation, net........... 34 (32) (79) 3,987 3,988 6,202 Amortization of unrecognized prior service costs........................ 3,455 3,455 4,918 (466) (461) (720) Amortization of (gain)/loss, net...... (3,477) (5,885) (3,755) 129 (396) (107) Other................................. - - 519 - - - -------- -------- -------- -------- -------- -------- Net periodic benefit cost............. $ 1,055 $ (2,301) $ 9,220 $ 11,098 $ 10,288 $ 16,571 ======== ======== ======== ======== ======== ======== (1) In July 1998, pension plan assets were transferred to ONEOK resulting in a settlement loss. For measurement purposes, an annual health care cost growth rate of 7.0% was assumed for 1999, 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 $2.0 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 in the company stock fund. The company's contributions were $3.7 million for 1999, $3.8 million for 1998, and $5.0 million for 1997. 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 79
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 was $802,251 for 1999, $992,000 for 1998, and $34,000 for 1997. 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 as a means to attract, retain and motivate employees and board members (Plan Participants). 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 five million shares of common stock may be granted under the LTISA Plan. Stock options and restricted shares under the LTISA plan are as follows: December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------- Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price --------- --------- --------- --------- ------- ---------- Outstanding, beginning of year.. 1,590,700 $36.106 665,400 $30.282 205,700 $29.250 Granted......................... 981,625 30.613 925,300 40.293 459,700 30.750 Exercised....................... - - - - - - Forfeited....................... (153,690) 31.985 - - - - --------- --------- ------- Outstanding, end of year........ 2,418,635 $34.139 1,590,700 $36.106 665,400 $30.282 ========= ========= ======= Weighted-average fair value of options granted during the year...................... $ 8.22 $ 9.12 $ 3.00 Stock options and restricted shares issued and outstanding at December 31, 1999, are as follows: Number Weighted- Weighted- Range of Issued Average Average Exercise and Contractual Exercise Price Outstanding Life in Years Price -------------- ----------- ------------- --------- Options: 1999.................... $27.813-32.125 800,995 10.0 $30.815 1998.................... 38.625-43.125 763,000 9.0 40.538 1997.................... 30.750 414,520 8.0 30.750 1996.................... 29.250 138,620 6.7 29.250 --------- 2,117,135 ========= Restricted shares: 1999.................... 27.813-32.125 165,000 9.0 29.616 1998.................... 38.625 136,500 8.0 38.625 --------- Total issued.......... 301,500 ========= 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 $3.28 in 1999, $6.88 in 1998 and $6.21 in 1997. The value of each dividend equivalent is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend 80
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: 1999 1998 1997 ------- ------- ------- Dividend yield.................... 6.25% 6.32% 6.58% Expected stock price volatility... 16.56% 15.95% 13.56% Risk-free interest rate........... 6.05% 5.67% 6.72% 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. A summary of options issued under the Plan by fiscal year is as follows: Shares Granted Total Shares to Officers Granted -------------- ------------ 1997...... - - 1998...... 690,000 1,246,500 1999...... 399,700 1,092,908 Each option has a term of 10 years and vests ratably over three years. 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 November 1997 through December 31, 1999, is as follows: December 31, 1999 1998 1997 - -------------------------------------------------------------------------------------------------- Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price --------- --------- --------- --------- --------- --------- Outstanding, beginning of year(1).................. 3,422,739 $ 7.494 2,366,435 $ 5.805 2,366,741 $5.805 Granted....................... 1,092,908 7.905 1,246,500 11.033 - - Exercised..................... - - (109,595) 5.564 (306) 0.050 Forfeited..................... (956,511) 10.124 (117,438) 10.770 - - Adjustment to May 1995 warrants.................... - - 36,837 - - - --------- --------- --------- Outstanding, end of year...... 3,559,136 $12.252 3,422,739 $ 7.494 2,366,435 $5.805 ========= ========= ========= (1) There was no outstanding stock or options prior to November 24, 1997. 81
Stock options and warrants issued and outstanding at December 31, 1999, are as follows: Number Weighted- Weighted- Range of Issued Average Average Exercise and Contractual Exercise Price Outstanding Life in Years Price --------------- ----------- ------------- -------- Exercisable: Fiscal 1995 $ 6.375-$ 9.125 64,800 5.0 $ 6.491 Fiscal 1996 8.000- 10.313 178,400 6.0 8.031 Fiscal 1996 13.750- 15.500 69,000 6.0 14.924 Fiscal 1997 9.500 136,000 7.0 9.500 Fiscal 1997 15.000 25,000 7.0 15.000 Fiscal 1997 14.268 50,000 2.0 14.268 Fiscal 1998 11.000 367,499 8.0 11.000 Fiscal 1998 8.563 16,331 8.0 8.563 Fiscal 1999 8.928 87,600 9.0 8.928 KOP Warrants 3.633 103,697 1.0 3.633 1993 Warrants 0.167 428,400 4.0 0.167 1995 Note Warrants 3.890 786,277 5.0 3.890 Other 0.050 305 7.0 0.050 --------- 2,313,309 --------- Not Exercisable: 1998 options $ 11.000 333,001 8.0 $11.000 1998 options 8.563 32,660 8.0 8.563 1999 options 8.928 686,500 9.0 8.928 1999 options 3.875- 6.125 193,666 9.0 5.855 --------- 1,245,827 --------- Total outstanding 3,559,136 ========= The weighted average fair value of options granted during 1999 and 1998 and estimated on the date of grant were $6.87 and $5.41. The fair value was calculated using the following assumptions: Year Ended December 31, 1999 1998 ---- ---- Dividend yield................... 0.00% 0.00% Expected stock price volatility.. 64.06% 61.72% Risk free interest rate.......... 6.76% 5.50% Expected option life............. 6 years 6 years Effect of Stock-Based Compensation on Earnings Per Share: 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 1999, 1998 and 1997 as shown in the table below. Year Ended December 31, 1999 1998 1997 ------------------------------------------------------------------- (Dollars in Thousands, Except Per Share Amounts) (Restated - Note 2) 82
Earnings available for common stock: As reported................................... $13,167 $32,058 $493,733 Pro forma..................................... 10,041 30,533 493,570 Earnings per common share (basic and diluted): As reported................................... $ 0.20 $ 0.48 $ 7.58 Pro forma..................................... 0.15 0.46 7.58 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 life insurance policies on which 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 certain conditions, each executive may transfer to the company their interest in the death benefit based on a predetermined formula, beginning no earlier than the first day of the calendar year following retirement or three years from the date of the policy. The liability associated with this program was $31.9 million as of December 31, 1999, and $57.9 million as of December 31, 1998. The obligations under this program can increase and decrease based on the company's total return to shareholders. This liability decreased approximately $10.5 million in 1999 based on the company's total return to shareholders. There was no change in the liability in 1998. Under current tax rules, payments to active employees in exchange for their interest in the death benefits may not be fully deductible by the company for income tax purposes. 12. COMMON STOCK, PREFERRED STOCK, PREFERENCE STOCK, AND OTHER MANDATORILY REDEEMABLE SECURITIES The company's Restated Articles of Incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 1999, 67,401,657 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. During 1999, a total of 1,819,856 original issue shares were purchased from the company. At December 31, 1999, 2,771,191 shares were available under the DSPP registration statement. In 1999, the company purchased 900,000 shares of common stock at an average price of $17.55 per share. The purchased shares were purchased with short-term debt and available funds. The purchased shares are held in treasury and are available for general corporate purposes, resale or retirement. These purchased shares are shown as $15.8 million in treasury stock on the accompanying Consolidated Balance Sheet. 83
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. At December 31, 1999, and 1998, the company had no preference stock outstanding. Other Mandatorily Redeemable Securities: On December 14, 1995, Western Resources Capital I, a wholly-owned trust, issued 4.0 million preferred securities of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, for $100 million. The trust interests 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 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 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 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. 13. COMMITMENTS AND CONTINGENCIES Purchase Orders and Contracts: 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 $190 million at December 31, 1999. 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, 1999, 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 84
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. Superfund Sites: In December 1999, the company was identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). The company has previously been associated with other Superfund sites for which the company's liability has been classified as de minimis and any potential obligations have been settled at minimal cost. Since 1993, the company has settled Superfund obligations at three sites for a total of $141,300. No Superfund obligations have been settled since 1994. The company's obligation, if any, at the Kansas City site is expected to be limited based upon previous experience and the limited nature of the company's business transactions with the previous owners of the site. In the opinion of the company's management, the resolution of this matter is not expected to have a material impact on the company's financial position or results of operations. 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. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. Approval of this study by the KCC is pending. The company's share of the cost for decommissioning in the 1999 study under the dismantlement method is $221 million in 1999 dollars. 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 $3.9 million in 1999 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% per year. The company's investment in the decommissioning fund, including reinvested earnings approximated $58.3 million at December 31, 1999, $52.1 million at December 31, 1998, and $43.5 million at December 31, 1997. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. Nuclear Insurance: The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability 85
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 mandated by the NRC. The company's share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund. The Owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, the company may be subject to retrospective assessments under the current policies of approximately $6 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, 1999, Wolf Creek's nuclear fuel commitments (company's share) were approximately $14 million for uranium concentrates expiring at various times through 2003, $26 million for enrichment expiring at various times through 2003 and $65.2 million for fabrication through 2025. At December 31, 1999, the company's coal contract commitments in 1999 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, 1999, the company's natural gas transportation commitments in 1999 dollars under the remaining terms of the contracts were approximately $29.1 million. The natural gas transportation contracts provide firm service to the company's gas burning facilities expiring at various times through 2010. 14. LEGAL PROCEEDINGS 86
The SEC commenced a private investigation in 1997 relating to, among other things, 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 in this investigation. The company, its subsidiary Westar Capital, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Monitoring), and certain present and former officers and directors of Protection One are defendants in a purported class action litigation pending in the United States District Court for the Central District of California, "Ronald Cats, et al., v. Protection One, Inc., et. al.", No. CV 99-3755 DT (RCx). Pursuant to an Order dated August 2, 1999, four pending purported class actions were consolidated into a single action. In March 2000, plaintiffs filed a Second Consolidated Amended Class Action Complaint (the Amended Complaint). Plaintiffs purport to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and notes, during the period of February 10, 1998, through November 12, 1999. The Amended Complaint asserts claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Monitoring, and certain present and former officers and directors of Protection One based on allegations that various statements concerning Protection One's financial results and operations for 1997 and 1998 were false and misleading and not in compliance with Generally Accepted Accounting Principals (GAAP). Plaintiffs allege, among other things, that former employees of Protection One have reported that Protection One lacked adequate internal accounting controls and that certain accounting information was unsupported or manipulated by management in order to avoid disclosure of accurate information. The Amended Complaint further asserts claims against the company and Westar as controlling persons under Sections 11 and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. A claim is also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Amended Complaint seeks an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. The company and Protection One believe that all the claims asserted in the Amended Complaint are without merit and intend to defend against them vigorously. The company and Protection One cannot currently predict the impact of this litigation which could be material. 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 disposition of such matters will not have a material adverse effect upon the company's overall financial position or results of operations. See also Note 15 for discussion of the FERC proceeding regarding the City of Wichita complaint. 15. RATE MATTERS AND REGULATION KCC Proceedings: In January 1997, the KCC entered an order reducing electric rates for both KPL and KGE. The order required KGE to reduce electric rates by $65 million cumulative, phased in over three years beginning in 1997. The order required KPL to reduce electric rates by $10 million in 1997 and issue two one-time rebates of $5 million in January 1998, and January 1999. On March 16, 2000, the Kansas Industrial Consumers (KIC), an organization of commercial and industrial users of electricity in Kansas, filed a complaint with the KCC requesting an investigation of Western Resources' and KGE's rates. The KIC alleges that these rates are not 87
based on current costs. The company will oppose this request vigorously but is unable to predict whether the KCC will open an investigation. FERC Proceeding: In September 1999, the City of Wichita filed a complaint with the Federal Energy Regulatory Commission (FERC) against the company, alleging improper affiliate transactions between KPL, a division of the company, and KGE, a wholly-owned subsidiary of the company. The City of Wichita requests the FERC to equalize the generation costs between KPL and KGE, in addition to other matters. FERC has issued an order setting this matter for hearing and has referred the case to a settlement judge. The hearing has been suspended pending settlement discussions between the parties. The company believes that the City of Wichita's complaint is without merit and intends to defend against it vigorously. 16. LEASES At December 31, 1999, 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) Rental payments: 1997................................ $ 71,126 1998................................ 70,796 1999................................ 71,771 Future commitments: 2000................................ 68,431 2001................................ 64,100 2002................................ 59,090 2003................................ 59,655 2004................................ 52,899 Thereafter.......................... 610,925 -------- Total future commitments......... $915,100 ======== 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 $19.1 million of this deferral remained on the Consolidated Balance Sheet at December 31, 1999. 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 88
million in 2003, $34.6 million in 2004, and $502.6 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 1999, $28.9 million for 1998, and $27.3 million for 1997. 17. INTERNATIONAL POWER DEVELOPMENT COSTS 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 recorded a $98.9 million charge to income in the fourth quarter of 1998 as a result of exiting this business. During 1999, the company terminated the employment of all employees, closed offices, discontinued all development activities, and terminated all other matters related to the activity of Wing in accordance with the terms of the exit plan. These activities were substantially completed by December 31, 1999. The actual costs incurred during 1999 to complete the exit plan approximated $16.9 million, which was $5.6 million less than the amount estimated at December 31, 1998. This was accounted for as a change in estimate in 1999. At December 31, 1999, approximately $380,000 of accrued exit fees and shut- down costs were included in other current liabilities on the accompanying Consolidated Balance Sheet. This amount represents employee settlement and severance costs expected to be paid in 2000. The detailed components of the 1999 activity to exit this business are as follows: (Dollars in Thousands) Accrued exit fees, shut-down and severance costs, balance at December 31, 1998............... $22,900 Actual costs incurred............................... (16,888) Change in estimate.................................. (5,632) ------- Accrued exit fees, change in estimate, shut-down and severance costs, balance at December 31, 1999..... $ 380 ======= 18. MERGER AGREEMENT WITH KANSAS CITY POWER & LIGHT COMPANY On March 18, 1998, the company signed an Amended and Restated Plan of Agreement and Plan of Merger with the Kansas City Power & Light Company (KCPL) under which KGE, KPL, a division of Western Resources, and KCPL would have been combined into a new company called Westar Energy, Inc. KCPL has notified the company that it has terminated the contemplated transaction. The company expensed costs related to the KCPL merger of approximately $17.6 million at December 31, 1999 and approximately $48 million at December 31, 1997 associated with the original merger agreement. 89
19. 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 $864.2 million on the sale and recorded tax expense of approximately $345 million in connection with this gain. 2O. 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, 1999 and 1998. The fair value of fixed-rate debt 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, 1999, 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 would not have a material effect on the company's financial position or results of operations. 90
The carrying values and estimated fair values of the company's financial instruments are as follows: Carrying Value Fair Value ---------------------------------- ---------------------------------- December 31, 1999 1998 1997 1999 1998 1997 - -------------------------------------------------------------- ---------------------------------- (Dollars in Thousands) Decommissioning trust.... $ 58,286 $ 52,093 $ 43,514 $ 58,286 $ 52,093 $ 43,514 Fixed-rate debt, net of current maturities..... 2,742,307 2,956,692 2,019,103 2,350,130 3,076,709 2,101,167 Redeemable preference stock.................. - - 50,000 - - 51,750 Other mandatorily redeemable securities.. 220,000 220,000 220,000 187,950 226,800 226,800 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, to maintain a market presence and to enhance system reliability. 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. The notional volumes and estimated fair values of the company's trading forward contracts and options are as follows at December 31: 1999 1998 1997 --------------------------------------------------------------------- Notional Notional Notional Volumes Estimated Volumes Estimated Volumes Estimated (MWH's) Fair Value (MWH's) Fair Value (MWH's) Fair Value -------- ---------- -------- ---------- -------- ---------- (Dollars in Thousands) Forward contracts: Purchased.......... 496,800 $14,800 1,535,600 $46,361 359,200 $8,604 Sold............... 478,400 14,404 1,535,600 46,141 359,200 8,806 Options: Purchased.......... 659,200 $ 5,079 148,800 $ 361 803,200 $1,607 Sold............... 336,480 6,013 64,000 195 120,800 512 Forward contracts and options had a net unrealized loss of $73,000 at December 31, 1999, a net unrealized gain of $40,000 at December 31, 1998, and a net unrealized loss of $127,000 at December 31, 1997. The notional volumes and estimated fair values of the company's non-trading forward 91
contract and options for electric positions are as follows at December 31: 1999 1998 1997 ---------------------------------------------------------------------- Notional Notional Notional Volumes Estimated Volumes Estimated Volumes Estimated (MWH's) Fair Value (MWH's) Fair Value (MWH's) Fair Value -------- ---------- -------- ---------- -------- ---------- (Dollars in Thousands) Forward contracts: Purchased......... 640,800 $18,221 - - - - Sold.............. 610,400 17,991 - - - - Options: Purchased......... 285,600 $ 445 - - - - Sold.............. 417,720 2,445 - - - - Non-trading forward contracts and options for electric positions had a net unrealized loss of $127,950 at December 31, 1999. No non-trading forward contracts and options for electric positions were held at December 31, 1998 and December 31, 1997. The notional volumes and estimated fair values of the company's non-trading forward contract and options for gas positions are as follows at December 31: 1999 1998 1997 ------------------------------------------------------------------------- Notional Notional Notional Volumes Estimated Volumes Estimated Volumes Estimated (MMBtu's) Fair Value (MMBtu's) Fair Value (MMBtu's) Fair Value ---------- ---------- --------- ---------- --------- ---------- (Dollars in Thousands) Forward contracts: Purchased......... 13,010,000 $31,002 - - - - Sold.............. 500,000 1,108 - - - - Options: Purchased......... 6,000,000 $ 971 - - - - Sold.............. 4,000,000 615 - - - - Non-trading forward contracts and options for gas positions had a net unrealized loss of $1,147,134 at December 31, 1999. No non-trading forward contracts and options for gas positions were held at December 31, 1998 and December 31, 1997. 92
21. INCOME TAXES Income tax expense is composed of the following components at December 31: 1999 1998 1997 -------- -------- -------- (Dollars in Thousands) (Restated - Note 2) Currently payable: Federal...................... $ 13,907 $52,993 $336,150 State........................ 9,622 10,881 72,143 Deferred: Federal...................... (43,090) (46,869) (15,723) State........................ (6,582) (4,185) (2,696) Amortization of investment tax credits................... (6,054) (6,065) (6,665) -------- ------- -------- Total income tax expense (benefit)..................... $(32,197) $6,755 $383,209 ======== ====== ======== Under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", temporary differences gave rise to deferred tax assets and deferred tax liabilities as follows at December 31: 1999 1998 1997 ---------- ---------- ---------- (Dollars in Thousands) (Restated - Note 2) Deferred tax assets: Deferred gain on sale-leaseback............. $ 87,220 $ 92,427 $ 97,634 Monitored services deferred tax assets...... 59,171 93,571 98,712 Other....................................... 131,976 146,086 93,786 ---------- ---------- ---------- Total deferred tax assets................. $ 278,367 $ 332,084 $ 290,132 ========== ========== ========== Deferred tax liabilities: Accelerated depreciation and other.......... $ 614,309 $ 613,730 $ 625,176 Acquisition premium......................... 283,157 291,156 299,162 Deferred future income taxes................ 218,937 206,114 213,658 Other....................................... 40,508 48,518 112,555 ---------- ---------- ---------- Total deferred tax liabilities............ $1,156,911 $1,159,518 $1,250,551 ========== ========== ========== Investment tax credits........................ $ 97,591 $ 103,645 $ 109,710 ========== ========== ========== Accumulated deferred income taxes, net........ $ 976,135 $ 931,079 $1,070,129 ========== ========== ========== 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. 93
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, 1999 1998 1997 - --------------------------------------------------------------------------- (Restated - Note 2) Effective income tax rate. . . . . . . . . (108.6%) 16.6% 43.5% Effect of: State income taxes. . . . . . . . . . . . (7.1) (7.3) (5.2) Amortization of investment tax credits. . 20.4 14.9 0.8 Corporate-owned life insurance policies . 28.0 22.4 0.9 Affordable housing tax credits. . . . . . 31.3 3.1 - Accelerated depreciation flow through and amortization, net . . . . . . . . . (12.2) (4.4) (0.4) Adjustment to tax provision . . . . . . . 4.3 (16.9) (3.6) Dividends received deduction. . . . . . . 34.3 23.9 - Amortization of goodwill. . . . . . . . . (19.3) (17.0) - Other . . . . . . . . . . . . . . . . . . (6.1) (0.3) (1.0) Statutory federal income tax rate. . . . . (35.0%) 35.0% 35.0% 22. RELATED PARTY The company and ONEOK have shared services agreements in which facilities, utility field work, information technology, customer support, bill processing, and human resources services are provided to and billed to one another. Payments for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. ONEOK paid the company $5.6 million in 1999 and $4.9 million in 1998, net of what the company owed ONEOK, for services. In 1999, the company sold 984,000 shares of ONEOK stock to ONEOK as a result of ONEOK's repurchase program. The company reduced its investment in ONEOK for proceeds received from this sale. All such shares were required to be sold to ONEOK in accordance with a Shareholder Agreement between the company and ONEOK. The company's ownership interest remains at approximately 45%. 23. 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 the company's wholesale and retail customers in Kansas and the customer service provided to these customers. 94
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 1.6 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. Year Ended December 31, 1999: Eliminating/ Fossil Nuclear Power Monitored Reconciling Generation Generation Delivery Services (1)Other (2)Items Total ---------- ---------- --------- ---------- ---------- ----------- ---------- (Dollars in Thousands) Restated Restated Restated Note 2 Note 2 Note 2 External sales..... $ 365,311 $ - $1,064,385 $ 605,176 $ 1,284 $ 2 $2,036,158 Internal sales..... 546,683 108,445 293,522 - - (948,650) - Depreciation and amortization...... 55,320 39,629 71,717 235,465 1,448 90 403,669 Earnings before interest and taxes 219,087 (25,214) 145,603 (20,675) (28,088) (26,252) 264,461 Interest expense... 294,104 Earnings/(loss)before income taxes...... (29,643) Identifiable assets 1,476,716 1,083,344 1,783,937 2,539,921 1,165,145 (59,171) 7,989,892 Year Ended December 31, 1998: Eliminating/ Fossil Nuclear Power Monitored Reconciling Generation Generation Delivery Services (3)Other (2)Items Total ---------- ---------- --------- ---------- ---------- ----------- ---------- (Dollars in Thousands) Restated Restated Restated Note 2 Note 2 Note 2 External sales.... $ 525,974 $ - $1,085,711 $ 421,095 $ 1,342 $ (68) $2,034,054 Internal sales.... 517,363 117,517 66,492 - - (701,372) - Depreciation and amortization..... 53,132 39,583 68,297 125,103 2,010 - 288,125 Earnings before interest and taxes 144,357 (20,920) 196,398 34,438 (99,608) 12,268 266,933 95
Interest expense.............. 226,120 Earnings before income taxes................. 40,813 Identifiable assets........... 1,360,102 1,121,509 1,788,943 2,489,667 1,269,013 (99,458) 7,929,776 Year Ended December 31, 1997: Eliminating/ Fossil Nuclear Power Monitored Reconciling Generation Generation Delivery (4)Services (5,6)Other (2,7)Items Total ----------- ---------- --------- ----------- ---------- ----------- --------- (Dollars in Thousands) Restated Restated Restated Note 2 Note 2 Note 2 External sales........................... $ 208,836 $ - $1,021,212 $ 152,347 $ 769,416 $ (46) $2,151,765 Internal sales........................... 517,167 102,330 66,492 - - (685,989) - Depreciation and amortization............ 53,831 65,902 63,590 53,292 32,223 - 268,838 Earnings before interest and taxes....... 149,825 (60,968) 173,809 (37,880) 913,466 (62,583) 1,075,669 Interest expense......................... 193,808 Earnings before income taxes............. 881,861 Identifiable assets...................... 1,337,591 1,154,522 1,721,021 1,579,086 1,238,088 (84,958) 6,945,350 (1) Earnings before interest and taxes (EBIT) includes investment earnings of $36.0 million, an impairment of marketable securities of $76.2 million and the write-off of deferred costs of $17.6 million. (2) Identifiable assets includes eliminating and reclassing balances to consolidate the monitored services business. (3) Earnings before interest and taxes (EBIT) includes investment earnings of $21.7 million and the write-off of international power development costs of $98.9 million. (4) EBIT includes monitored services special charge of $11.5 million. (5) EBIT includes investment earnings of $37.8 million and gain on sale of Tyco securities of $864.3 million. (6) Includes natural gas operations. The company contributed substantially all of its natural gas business in exchange for a 45% equity interest in ONEOK in November 1997. (7) EBIT includes write-off of deferred merger costs of $48 million. 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 are as follows: Year Ended December 31, 1999 1998 ------------------------------------------------------------------- (Dollars in Thousands) External sales: North America operations......... $1,873,152 $1,990,329 International operations......... 163,006 43,725 ---------- ---------- Total.......................... $2,036,158 $2,034,054 ========== ========== Property, plant and equipment, net: North America operations......... $3,881,294 $3,792,645 International operations......... 8,150 7,271 ---------- ---------- Total.......................... $3,889,444 $3,799,916 ========== ========== 24. QUARTERLY RESULTS (UNAUDITED) The amounts in the table are unaudited but, in the opinion of management, contain all 96
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) 1999 (Restated) ---- Sales............................ $ 460,582 $ 476,142 $ 648,998 $ 450,436 Gross profit..................... 312,655 324,407 425,087 311,022 Net income before extraordinary gain(1)......... 19,980 17,722 53,203 (88,351) Net income(1).................... 19,980 17,722 53,203 (76,609) Basic earnings per share available for common stock before extraordinary gain..... $ 0.30 $ 0.26 $ 0.78 $ (1.32) Cash dividend per common share... $ 0.535 $ 0.535 $ 0.535 $ 0.535 Market price per common share: High........................... $ 33.875 $ 29.375 $ 27.125 $ 23.8125 Low............................ $ 26.6875 $ 23.75 $ 20.375 $ 16.8125 1998 (Restated) ---- Sales............................ $ 382,343 $ 463,301 $ 701,402 $ 487,008 Gross profit..................... 252,040 291,338 365,415 302,002 Net income before extraordinary gain(2)......... 27,903 22,995 67,470 (84,310) Net income(2).................... 27,903 24,586 67,470 (84,310) Basic earnings per share available for common stock before extraordinary gain..... $ 0.41 $ 0.32 $ 1.02 $ (1.29) Cash dividend per common share... $ 0.535 $ 0.535 $ 0.535 $ 0.535 Market price per common share: High........................... $ 44.188 $ 42.688 $ 41.625 $ 43.250 Low............................ $ 40.000 $ 36.875 $ 37.688 $ 32.563 (1) The effect of Protection One's change in accounting principle effected income in the third quarter of 1999 by increasing amortization expense by $40 million (2) The loss in the fourth quarter of 1998, is primarily attributable to a $98.9 million charge to income to exit the company's international power development business 1997 (Restated) ---- Sales............................ $ 626,198 $ 454,006 $ 559,996 $ 511,565 Gross profit..................... 310,448 265,533 338,667 269,594 Net income before extraordinary gain(3),(4)..... 37,805 22,737 507,292 (69,182) Net income....................... 37,805 22,737 507,292 (69,182) Basic earnings per share......... $ 0.56 $ 0.33 $ 7.76 $ (1.07) Cash dividend per common share... $ 0.525 $ 0.525 $ 0.525 $ 0.525 97
Market price per common share: High......................... $ 31.50 $ 32.75 $ 35.00 $ 43.438 Low.......................... $ 30.00 $ 29.75 $ 32.25 $ 33.625 (3) 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 $11.5 million. (4) During the third quarter of 1997, the company recorded a pre-tax gain of approximately $864 million upon selling its Tyco common stock. In addition, the net effect of the restatement discussed in Note 2 of the Notes to Consolidated Financial Statements has been reflected in the appropriate quarterly results as follows: As Previously Reported Restatement As Restated ---------------------- -------------------- -------------------- Per Share Per Share Per Share Amount Amounts Amount Amounts Amount Amounts --------- ---------- -------- ---------- -------- --------- (Dollars in thousands, except for per share amounts) Net income before extraordinary gain - ------------------------------------ 1999 - Quarter Ended: March 31.............................. $ 20,747 $ 0.31 $ (767) $ (0.01) $ 19,980 $ 0.30 June 30............................... 18,489 0.28 (767) (0.01) 17,722 0.27 September 30.......................... 49,010 0.73 4,193 0.05 53,203 0.78 December 31........................... (87,529) (1.31) (822) (0.02) (88,351) (1.33) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1999.... $ 717 $ 0.01 $ 1,837 $ 0.01 $ 2,554 $ 0.02 ======== ========= ======== ========= ======== ========= Earnings available for common stock - ----------------------------------- 1999 - Quarter Ended: March 31.............................. $ 20,465 $ 0.31 $ (767) $ (0.01) $ 19,698 $ 0.30 June 30............................... 18,207 0.27 (767) (0.01) 17,440 0.26 September 30.......................... 48,728 0.72 4,193 0.06 52,921 0.78 December 31........................... (76,070) (1.13) (822) (0.01) (76,892) (1.14) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1999.... $ 11,330 $ 0.17 $ 1,837 $ 0.03 $ 13,167 $ 0.20 ======== ========= ======== ========= ======== ========= Net income before extraordinary gain - ------------------------------------ 1998 - Quarter Ended: March 31.............................. $ 29,813 $ 0.46 $ (1,910) $ (0.03) $ 27,903 $ 0.43 June 30............................... 29,415 0.45 (6,420) (0.10) 22,995 0.35 September 30.......................... 71,421 1.09 (3,951) (0.06) 67,470 1.03 December 31........................... (84,484) (1.30) 174 0.01 (84,310) (1.29) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1998.... $ 46,165 $ 0.70 $(12,107) $ (0.18) $ 34,058 $ 0.52 ======== ========= ======== ========= ======== ========= Earnings available for common stock - ----------------------------------- 1998 - Quarter Ended: March 31.............................. $ 28,583 $ 0.44 $ (1,910) $ (0.03) $ 26,673 $ 0.41 June 30............................... 29,209 0.45 (6,420) (0.11) 22,789 0.34 September 30.......................... 71,139 1.08 (3,951) (0.06) 67,188 1.02 December 31........................... (84,766) (1.30) 174 0.01 (84,592) (1.29) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1998.... $ 44,165 $ 0.67 $(12,107) $ (0.19) $32,058 $ 0.48 ======== ========= ======== ========= ======= ======== Net income before extraordinary gain - ------------------------------------ 1997 - Quarter Ended: March 31.............................. $ 41,033 $ 0.63 $ (3,228) $ (0.05) $ 37,805 $ 0.58 June 30............................... 24,335 0.37 (1,598) (0.02) 22,737 0.35 September 30.......................... 508,372 7.79 (1,080) (0.01) 507,292 7.78 December 31........................... (74,222) (1.12) 5,040 0.07 (69,182) (1.05) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1997.... $499,518 $ 7.67 $ (866) $ (0.01) $498,652 $ 7.66 ======== ========= ======== ========= ======== ========= 98
Earnings available for common stock - ----------------------------------- 1997 - Quarter Ended: March 31.............................. $ 39,803 $ 0.61 $ (3,228) $ (0.05) $ 36,575 $ 0.56 June 30............................... 23,106 0.36 (1,598) (0.03) 21,508 0.33 September 30.......................... 507,142 7.77 (1,080) (0.01) 506,062 7.76 December 31........................... (75,452) (1.15) 5,040 0.08 (70,412) (1.07) -------- --------- -------- --------- -------- --------- For the Year Ended December 31, 1997.... $494,599 $ 7.59 $ (866) $ (0.01) $493,733 $ 7.58 ======== ========= ======== ========= ======== ========= The restatement did not impact previously reported revenues or gross profits. 25. SUBSEQUENT EVENTS Marketable Securities: Through March 16, 2000, the company sold a significant portion of an equity investment in a gas compression company and realized a gain of $72.6 million. In February 2000, Metrocall, Inc., a paging company whose securities were included in our investment portfolio at December 31, 1999, made an announcement that significantly increased the market value of paging company securities in the public markets. During the first quarter of 2000, the remainder of these paging securities were sold and a gain of $24.9 million was realized. Retirement of Protection One Debt: In the first quarter of 2000, Westar Capital, purchased an additional $46.3 million of Protection One bonds in the open market and recognized an extraordinary gain of $14.4 million, net of tax. Protection One European Operations: On February 29, 2000, Westar Capital purchased the continental European and United Kingdom operations of Protection One, and certain investments held by a subsidiary of Protection One for an aggregate purchase price of $244 million. The basis of the net assets sold did not change and no gain or loss was recorded for this related party transaction. Terms of the agreement were approved by a special committee of outside directors of Protection One. The special committee obtained a fairness opinion from an investment banker. Dividend Policy: The company's board of directors reviews the company's dividend policy on an annual basis. Among the factors the board of directors considers in determining the company's dividend policy are earnings, cash flows, capitalization ratios, competition and regulatory conditions. In January 2000, the company's board of directors declared a first-quarter 2000 dividend of 53 1/2 cents per share. In March, the company announced a new dividend policy that will result in quarterly dividends of $.30 per share or $1.20 per share on an annual basis to be effective with the declaration of the July 2000 dividend. Corporate Restructuring: On March 28, 2000, the company's board of directors approved the separation of its electric and non-electric utility businesses. The separation is currently expected to be effected through an exchange offer to be made to shareholders in the third quarter of 2000. The exchange ratio will be described in materials furnished to shareholders upon commencement of the exchange offer. The impact on the company's financial position and operating results cannot be known until the exchange ratio is determined. The company expects to complete the separation in the fourth quarter of 2000, but no assurance can be given that the separation will be completed. 99
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 2000 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 2000 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 2000 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. 100
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, 1999, 1998 and 1997 Consolidated Statements of Income, for the years ended December 31, 1999, 1998 and 1997 Consolidated Statements of Comprehensive Income, for the years ended December 31, 1999, 1998 and 1997 Consolidated Statements of Cash Flows, for the years ended December 31, 1999, 1998 and 1997 Consolidated Statements of Cumulative Preferred and Preference Stock, December 31, 1999, 1998 and 1997 Consolidated Statements of Shareholders' Equity, for the years ended December 31, 1999, 1998 and 1997 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 November 15, 1999 - Press release regarding Western Resources third-quarter earnings and plans to purchase Protection One debt. Form 8-K/A filed December 2, 1999 - Reporting a correction to attachment 2 of Western Resources third-quarter results reported on Form 8-K, dated November 15, 1999. Form 8-K filed December 3, 1999 - Press release reporting Western Resources' and Protection One's receipt of extension on bank waiver. Form 8-K filed December 8, 1999 - Presentation distributed by Western Resources to financial analysts. Form 8-K filed December 20, 1999 - Press release reporting Westar Capital, a subsidiary of Western Resources, acquisition of the debt and assumption of the lenders' obligations under Protection One's revolving credit facility. 101
Form 8-K filed January 3, 2000 - Press release reporting that Kansas City Power & Light Company terminated the proposed merger with Western Resources. Form 8-K filed January 26, 2000 - Press release reporting that Western Resources reached an agreement with its banks to eliminate the cross- default provisions relating to Protection One, Inc. Form 8-K filed January 27, 2000 - Press release reporting Western Resources declaration of a first quarter dividend and that the Board of Directors will consider a stock dividend for the balance of the current annual dividend. Form 8-K filed March 1, 2000 - Press release reporting Westar Capital's purchase of Protection One, Inc.'s continental European and United Kingdom operations, and certain other assets of Protection One. 102
EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. Description ----------- 3(a) -By-laws of the company, as amended March 16, 2000. (filed electronically) I 3(b) -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(c) -Certificate of Amendment to Restated Articles of Incorporation I of the company dated March 29, 1991. 3(d) -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(e) -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(f) -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(g) -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(h) -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(i) -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(j) -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, October4, 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) 103
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 June 30, 1998 Form 10-Q) 4(v) -Form of Note for $400 million 6.25% Putable/Callable Notes due August I 15, 2018, Putable/Callable August 15, 2003 (filed as Exhibit 4.2 to the June 30, 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) 104
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) -Deferred Compensation Plan (filed as Exhibit 10(i) to the I December 31, 1993 Form 10-K) 10(g) -Short-term Incentive Plan (filed as Exhibit 10(k) to the I December 31, 1993 Form 10-K) 10(h) -Outside Directors' Deferred Compensation Plan (filed as Exhibit I 10(l) to the December 31, 1993 Form 10-K) 10(i) -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(j) -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(k) -Form of Shareholder Agreement between New ONEOK and the I company. (filed as Exhibit 99.3 to the December 12, 1997 Form 8-K) 10(l) -Form of Split Dollar Insurance Agreement (filed as Exhibit 10.3 I to the June 30, 1998 Form 10-Q) 10(m) -Amendment to Letter Agreement between the company and David C. I Wittig, dated April 27, 1995 (filed as Exhibit 10 to the June 30, 1998 Form 10-Q/A) 10(n) -Letter Agreement between the company and Douglas T. Lake, dated August 17, 1998. (filed electronically) 12 -Computation of Ratio of Consolidated Earnings to Fixed Charges-Restated. (filed electronically) 21 -Subsidiaries of the Registrant. (filed electronically) 23 -Consent of Independent Public Accountants, Arthur Andersen LLP. (filed electronically) 27 -Financial Data Schedule-Restated. (filed electronically) 105
WESTERN RESOURCES, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands) Balance at Charged to Charged to Balance Beginning Costs and Other at End Description of Period Expenses Accounts(a) Deductions of Period ----------- --------- -------- ----------- ---------- --------- Year ended December 31, 1997 Allowances deducted from assets for doubtful accounts........ $ 6,255 $ 16,592 $ 4,578 $ (19,034) $ 8,391 Monitored services special charge (b).......................... - 3,856 - - 3,856 Year ended December 31, 1998 Allowances deducted from assets for doubtful accounts........ 8,391 24,726 2,289 (5,862) 29,544 Monitored services special charge (b).......................... 3,856 - - (2,831) 1,025 Accrued exit fees, change in estimate, shut-down and severance costs (c)........................... - 22,900 - - 22,900 Year ended December 31, 1999 Allowances deducted from assets for doubtful accounts........ 29,544 24,302 - (18,081) 35,765 Monitored services special charge (b).......................... 1,025 - - (1,025) - Accrued exit fees, shut-down and severance costs (c)............. 22,900 (5,632) - (16,888) 380 (a) Allowances recorded on receivables purchased in conjunction with acquisitions of customer accounts. (b) Consists of costs to close duplicate facilities and severance and compensation benefits. (c) See Note 17 of Notes to the Consolidated Financial Statements for further information. 106
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. Date February 2, 2001 By /s/ DAVID C. WITTIG ---------------- ---------------------------------------------- David C. Wittig, Chairman of the Board, President and Chief Executive Officer 107
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, DAVID C. WITTIG President and Chief February , 2001 - --------------------------- Executive Officer ----------------- (David C. Wittig) (Principal Executive Officer) Senior Vice President, JAMES A. MARTIN and Treasurer February , 2001 - --------------------------- (Principal Financial and ----------------- (James A. Martin) Accounting Officer) FRANK J. BECKER Director February , 2001 - --------------------------- ----------------- (Frank J. Becker) GENE A. BUDIG Director February , 2001 - --------------------------- ----------------- (Gene A. Budig) CHARLES Q. CHANDLER, IV Director February , 2001 - ---------------------------- ----------------- (Charles Q. Chandler, IV) JOHN C. DICUS Director February , 2001 - --------------------------- ----------------- (John C. Dicus) DOUGLAS T. LAKE Director February , 2001 - --------------------------- ----------------- (Douglas T. Lake) OWEN F. LEONARD Director February , 2001 - --------------------------- ----------------- (Owen F. Leonard) JOHN C. NETTELS, JR. Director February , 2001 - --------------------------- ----------------- (John C. Nettels, Jr.) JANE DRESNER SADAKA Director February , 2001 - --------------------------- ----------------- (Jane Dresner Sadaka) LOUIS W. SMITH Director February , 2001 - --------------------------- ----------------- (Louis W. Smith) 108
Exhibit 3 WESTERN RESOURCES, INC. BY-LAWS (as amended March 16, 2000) ARTICLE I STOCKHOLDERS Section 1. The annual meeting of the stockholders of the Company shall be held on such day and at such time as the Board of Directors may deem reasonable and appropriate, at the principal office of the Company in the City of Topeka, Kansas, or such other place as the Board of Directors may designate for the purpose of electing Directors and transacting such other business as may properly be brought before the meeting. Section 2. Special meetings of the stockholders may be held upon call of the Board of Directors or the Chairman of the Board or the President, at such time and at such place within or without the State of Kansas as may be stated in the call and notice. Section 3. Notice stating the place, day and hour of every meeting of the stockholders, and in the case of a special meeting further stating the purpose for which such meeting is called, shall be mailed at least ten days before the meeting to each stockholder of record who shall be entitled to vote thereat, at the last known post office address of each such stockholder as it appears upon the books of the Company. Such further notice shall be given by mail, publication or otherwise, as may be required by law. Section 4. The holders of record of a majority of the shares of the capital stock of the Company issued and outstanding, entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the stockholders, and the vote of a majority of such quorum shall be necessary for the transaction of any business, unless otherwise provided by law, by the Articles of Incorporation or by the By-laws. If at any meeting there shall be no quorum, the holders of record, entitled to vote, of a majority of such shares of stock so present or represented may adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall have been obtained, when any business may be transacted which might have been transacted at the meeting as first convened had there been a quorum. Section 5. Meetings of the stockholders shall be presided over by the Chairman of the Board or, if he is not present, by the President or, in his absence, by a Vice President. In the event that none of such officers be present, then the meeting shall be presided over by a chairman to be chosen at the meeting. The Secretary of the Company or, if he is not present, an Assistant Secretary of the Company or, if neither the Secretary nor an Assistant Secretary is present, a secretary to be chosen at the meeting shall act as secretary of the meeting. Section 6. At all meetings of the stockholders every holder of record of the shares of the capital stock of the Company, entitled to vote thereat, may vote thereat either in person or by proxy.
Section 7. At all elections of directors the voting shall be by written ballot. Section 8. The Board of Directors shall have power to close the stock transfer books of the Company for a period not exceeding sixty days preceding the date of - - (a) Any meeting of the stockholders; (b) Any payment of any dividends; (c) Any allotment of rights; (d) Any effective date of change or conversion or exchange of capital stock; or, in lieu of closing the stock transfer books, the Board of Directors may fix in advance a date not exceeding sixty days preceding the effective date of any of the above enumerated transactions, and in such case only such stockholders as shall be stockholders of record on the date so fixed shall be entitled to receive notice of and to vote at such meeting, or to receive payment of such dividend, or to receive allotment of rights, or to exercise rights of change, conversion or exchange of capital stock, as the case may be, or to participate in any of the above transactions, notwithstanding any transfer of any stock on the books of the Company after such record date fixed as aforesaid. ARTICLE II DIRECTORS Section 1. Subject to the provisions of the Articles of Incorporation, the Directors shall be elected at the regular annual meeting of stockholders, but if such election of Directors is not held on the day of the annual meeting, the Directors shall cause the election to be held as soon thereafter as conveniently may be. Also, subject to the provisions of the Articles of Incorporation, the Directors shall be divided into three classes, which shall be as nearly equal in number as possible, and no class shall include fewer than two Directors. Directors shall hold office for a term of three years and until their successors are elected and qualified. Each class of Directors shall be designated by the year in which its term ends. The Board shall fill vacancies in any class in the manner prescribed in this Article II, provided that any such newly elected Director shall serve for the remainder of the term applicable to the vacancy being filled. Notwithstanding the foregoing, whenever the holders of the preferred stock or preference stock issued by the Company shall have the right, voting separately by class, to elect Directors at an annual or special meeting of the stockholders, the election, term of office, and filling of vacancies of such Directors shall be governed by the terms of the Articles of Incorporation applicable thereto, and such Directors so elected shall not be divided into classes pursuant to this paragraph. Directors elected by a vote of the holders of preferred stock or preference stock as provided in the Articles of Incorporation shall hold office only so long as is required by the Articles of Incorporation. Except as otherwise provided in the By-laws and Articles of Incorporation, no Director shall be removed except for cause. This paragraph shall not be amended or repealed, and no provision inconsistent herewith shall be adopted, without the affirmative vote of the holders of at least 80% of the outstanding shares of stock of the Company entitled to vote in any election. Each director who is not a salaried full time officer or employee of the Company shall be conclusively deemed to have resigned from the Board of Directors of the Company if he retires, resigns, or is removed from the primary business position which he held at the time of his election to the Board.
No director who is not a salaried full time officer or employee of the Company shall be designated by the Board of Directors of the Company as a nominee for re-election to the Board of Directors at an annual meeting of stockholders if he shall have attained the age of seventy (70) at year-end prior to such annual meeting. No director who is a salaried full time officer or employee of the Company shall be designated by the Board of Directors of the Company as a nominee for re-election to the Board of Directors at an annual meeting of stockholders, if he shall have attained the age of sixty-five (65) at year-end prior to such annual meeting, or if he is no longer a full time officer or employee of the Company, or if he has been removed, during the 12 month period prior to Board action on nominees, from the position he previously held with the Company, except that any chief executive officer serving on the Board may be re-nominated for a maximum of two three-year terms after his retirement as chief executive officer. A majority of the members of the Board shall constitute a quorum for the filling of vacancies of the Board of Directors and the transaction of business, but if at any meeting of the Board there shall be less than a quorum present, a majority of the Directors present may adjourn the meeting from time to time without notice, other than announcement of the meeting, until a quorum shall have been obtained, when any business may be transacted which might have been transacted at the meeting as first convened had there been a quorum. The acts of a majority of the Directors present at any meeting at which there is a quorum shall, except as otherwise provided by law, by the Articles of Incorporation or the By-Laws, be the acts of the Board. Section 2. Vacancies in the Board of Directors, caused by death, resignation or otherwise, may be filled at any meeting of the Board of Directors and if the remaining directors constitute less than a quorum, by such remaining directors, and the directors so elected shall hold office for the remainder of the terms applicable to the class to which they were elected and until their successors are elected and qualified. Section 3. Meetings of the Board of Directors shall be held at such place within or without the State of Kansas as may from time to time be fixed by resolution of the Board or as may be specified in the call of any meeting. Regular meetings of the Board shall be held at such time as may from time to time be fixed by resolution of the Board, and notice of such meetings need not be given. Special meetings of the Board may be held at any time upon call of the Chairman of the Board or the President or a Vice President, by oral, telegraphic or written notice, duly served on or sent or mailed to each director not less than the day prior to any such meeting. Members of the Board may participate in any meeting of such Board by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such meeting shall constitute presence in person at the meeting. A meeting of the Board may be held without notice immediately before or after the annual meeting of the stockholders at the same place at which such meeting is held. Any meeting may be held without notice if all of the directors are present at the meeting, or if all of the directors sign a waiver thereof in writing. Any action required or permitted to be taken at any meeting of the board of directors may be taken without a meeting if all members of the board consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the board. Section 4. Meetings of the Board of Directors shall be presided over by the Chairman of the Board, or, if he is not present, by the President or, if he is absent, by a Vice President. In the event none of such officers are present, then the meeting shall be presided over by a chairman to be chosen at the meeting. The Secretary of the Company or, if he is not
present, an Assistant Secretary of the Company or, if neither the Secretary nor an Assistant Secretary is present, a secretary to be chosen at the meeting shall act as secretary of the meeting. Section 5. Each director of the Company who is not a salaried officer or salaried employee of the Company shall be entitled to receive such remuneration for serving as a director and as a member of any committee of the Board as may be fixed from time to time by the Board of Directors. ARTICLE III OFFICERS Section 1. The Board of Directors shall choose one of its number President of the Company and shall appoint one or more Vice Presidents, a Secretary and a Treasurer of the Company and from time to time may appoint such Assistant Secretaries, Assistant Treasurers, and other officers and agents of the Company as it may deem proper. Any officer may hold more than one office. Section 2. The term of office of all officers shall be one year or until the respective successors are chosen or appointed, but any officer or agent may be removed, with or without cause, at any time by the affirmative vote of a majority of the members of the Board then in office. Section 3. Subject to such limitations as the Board of Directors may from time to time prescribe, the officers of the Company shall each have such powers and duties as generally pertain to their respective offices, as well as such powers and duties as from time to time may be conferred by the Board of Directors. Section 4. The salaries of all officers and agents of the Company shall be fixed by the Board of Directors, or pursuant to such authority as the Board may from time to time prescribe. ARTICLE IV CERTIFICATES OF STOCK Section 1. The interest of each shareholder in the Company shall be evidenced by a certificate or certificates for shares of stock of the Company in such form as the Board of Directors may from time to time prescribe or by book entry upon the books and records of the Company. Certificates for shares of stock of the Company shall be signed by the Chairman of the Board or the President or any Vice President and the Treasurer or any Assistant Treasurer of this corporation and sealed with its corporate seal, or when the same bear the facsimile signature of the Chairman of the Board or the President or any Vice President and of the Treasurer or any Assistant Treasurer of the corporation and its facsimile seal and shall be countersigned and registered in such manner, if any, as the Board may by resolution, prescribe. Section 2. The shares of stock of the Company shall be transferable only on the books of the Company by the holders thereof in person or by duly authorized attorney, upon surrender for cancellation of certificates, if certificated, for a like number of shares of the same class of stock, with duly executed assignment and power of transfer endorsed thereon or attached thereto, or if uncertificated, with other appropriate evidence of transfer, with such proof of the authenticity of the signatures as the Company or its agents may reasonably require.
Section 3. No certificate for shares of stock of the Company shall be issued in place of any certificate alleged to have been lost, stolen or destroyed, except upon production of such evidence of the loss, theft, or destruction, and upon indemnification of the Company and its agents to such extent and in such manner as the Board of Directors may from time to time prescribe. ARTICLE V CHECKS, NOTES, ETC. All checks and drafts on the Company's bank accounts and all bills of exchange and promissory notes, and all acceptances, obligations and other instruments for the payment of money, shall be signed by such officer or officers or agent or agents as shall be thereunto authorized from time to time by the Board of Directors; provided that checks drawn on the Company's dividend, general and special accounts may bear the facsimile signature, affixed thereto by a mechanical device, of such officer or agent as the Board of Directors shall authorize. ARTICLE VI FISCAL YEAR The Fiscal year of the Company shall begin on the first day of January in each year and shall end on the thirty-first day of December following. ARTICLE VII CORPORATE SEAL The corporate seal shall have inscribed thereon the name of the Company and the words "Corporate Seal Kansas".
Exhibit 10 August 17, 1998 Mr. Douglas T. Lake 29 Sturgis Road Bronxville, New York 10708 Dear Doug, In accordance with our recent discussions, I would like to outline for you some terms for a position with Western Resources. Obviously, any agreement is subject to approval of the Western Resources Board of Directors. I am pleased to offer you the position of Executive Vice President, Chief Strategic Officer for Western Resources. In addition, you would serve as a member of the Company's Executive Council and participate with other senior officers in the formation and implementation of corporate policy regarding all aspects of the Company's operations. In your position, you would be primarily responsible for leading our efforts to grow our business as well as the businesses of our subsidiaries. Where appropriate, you would be expected to serve on subsidiary boards. In addition, we would expect you to open and manage an office in New York City to be staffed with a sufficient number of financial analysts in order to provide much of the analytical work for which we currently rely on bankers. While we would expect you to spend at least half of your time in Topeka and to establish your primary residence here, you would be expected to travel extensively. Your annual base compensation would be set at $325,000. You would receive a $350,000 signing bonus if you begin your employment prior to September 1, 1998. In addition to this base compensation, you would participate in the Company's short- and long-term incentive plans for officers. The short-term plan, while subject to change, would provide you an opportunity for additional cash compensation of up to 60% of base pay. You would also receive 30,000 stock options and 13,500 restricted shares in 1998, under the long-term plan. In addition, you would be enrolled in Western Resources' executive salary continuation plan. If you are still an employee of Western Resources (or its successor or one of its affiliates) as of September 1, 2000, you would receive a $500,000 payout. Likewise, if you are an employee on September 1, 2002, you would receive $1,000,000. In the event your employment is terminated prior to these respective dates by the Company without "Cause" or by you for "Good Reason," as those terms are defined in the Company's Change of Control Agreements, you would receive $500,000 if such termination is prior to September 1, 2000 or $1,000,000 if after September 1, 2000 but before September 1, 2002. In addition to the above, you will receive all benefits which are customarily offered to officers who serve on the Company's Executive Council. These include a deferred compensation plan, a 401K savings plan, a qualified retirement plan, medical/dental insurance, life insurance, accidental death and dismemberment insurance, short- and long-term disability protection, sick leave, vacation and holiday leave, up to $10,000 annually to cover financial planning and tax preparation as well as $10,000 for legal assistance in
that regard, a car allowance, personal use of a cellular phone, a club membership, a change of control agreement, matching gift, and relocation benefits. I have enclosed a schedule that sets forth this information in greater detail. Doug, I look forward too hearing from you on this matter. Please call if you would like to discuss any of these matters in more detail. Sincerely, David C. Wittig NAME: Douglas T. Lake POSITION: Executive Vice President, Chief Strategic Officer PAY GRADE: 5
COMPENSATION COMMENTS - ------------ ------------ Base Salary $325,000 Paid on the 15th and last day of the month Short Term Incentive Yes Performance related cash award (target of 60% of Base Salary) Payable in first quarter following close of performance period Long Term Incentive Yes Non-qualified stock options and dividend equivalents 30,000 stock options and 13,5000 restricted shares in 1998 BENEFITS - -------- Medical/Dental Yes Noncontributory medical; dental premium split 50/50 Life Insurance Yes 1X salary basic and AD&D - noncontributory; Up to 4X salary supplemental - employee paid; premium fixed at age of entry; supplemental fully portable upon termination/ retirement Qualified Retirement Plan Elig. After 1 yr. Provides approx. 37% of final 5 year's average base pay with 20 years of service. Savings Plan Elig. After 1 mo. 401(k) Plan allows 14% up to $10,000 pre-tax and 4% after tax Company matches first 6% of base pay contributed at 50% after 1 year of service. Executive Salary Continuation Plan Yes Full vesting with 15 years service or age 65. Provides 61.7% of final 3 year's pay at age 65. Lesser benefit payable below age 65. Earliest commencement is age 50, actuarially reduced for age below 60 and service less than 15 years. Benefit reduced by Qualified Retirement Plan benefit.
Deferred Compensation Yes Maximum deferral 100% of Base Salary; 100% of cash incentive compensation. (Long term Incentive comp. shares not eligible for deferral). Vacation Yes 4 weeks Holidays Yes 10 days total; 9 fixed, 1 floating Sick Leave Yes 7 days per year until 12 accumulated, then accrue 14 days per year; 180 days maximum Short Term Disability Yes Performance related cash award (target of 60% of Base Salary) Payable in first quarter following close of performance period Long Term Disability Yes Provides 60% Base Salary up to $5,000 per month less Social Security; payable to age 65. Car Allowance Yes Monthly car allowance $571, grossed up for anticipated taxes ($935 includes taxes). Financial Planning Yes Up to $10,000 annually for financial planning and tax related expenses, and up to $10,000 for associated legal fees and tax preparation expenses. Change of Control Agreement Yes The Western Resources Change of Control Agreement provides specified benefits to a select group of management and executive employees of the company in order that they may advise the Board whether a proposed change in control would be in the best interests of the company and its shareowners without being influenced by the uncertainties of their own situation. In your case, the applicable
severance multiple will be 2.99. Club Membership Yes Company paid membership to Topeka Country Club. Company will reimburse for monthly dues/capital expenses. Relocation Yes Company will pay for cost of moving household goods and one auto. Company will pay up to 90 days storage. You will receive a cash payment in the amount of 15% of the appraised value of your Bronxville residence (even if you choose to keep such residence). Matching Gift Yes The Company's matching gift program provides matching contributions to qualified entities on a 2 for 1 basis of up to $5,000 per year (maximum match of $10,000 per year).
Restated 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) Year Ended December 31, ---------------------------------------------------------- 1999 1998 1997 1996 1995 -------- -------- ---------- -------- -------- Earnings from continuing operations(1)................ $(45,460) $ 35,799 $ 879,556 $255,052 $265,068 -------- -------- ---------- -------- -------- Fixed Charges: Interest expense........................ 294,104 226,120 193,808 152,551 123,821 Interest on Corporate-owned Life Insurance Borrowings............. 36,908 38,236 36,167 35,151 32,325 Interest Applicable to Rentals............................... 34,252 32,796 34,514 32,965 31,650 -------- -------- ---------- -------- -------- Total Fixed Charges................. 365,264 297,152 264,489 220,667 187,796 -------- -------- ---------- -------- -------- Distributed income of equity investees................................ 3,728 3,812 - - - Preferred and Preference Dividend Requirements: Preferred and Preference Dividends............................. 1,129 3,591 4,919 14,839 13,419 Income Tax Required..................... 746 1,095 3,798 7,562 6,160 -------- -------- ---------- -------- -------- Total Preferred and Preference Dividend Requirements...................... 1,875 4,686 8,717 22,401 19,579 -------- -------- ---------- -------- -------- Total Fixed Charges and Preferred and Preference Dividend Requirements........................... 367,139 301,838 273,206 243,068 207,375 -------- -------- ---------- -------- -------- Earnings (2).............................. $323,532 $336,763 $1,144,045 $475,719 $452,864 ======== ======== ========== ======== ======== Ratio of Earnings to Fixed Charges (3).............................. 0.89 1.13 4.33 2.16 2.41 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements................... 0.88 1.12 4.19 1.96 2.18 (1) Earnings from continuing operations consists of loss or earnings before extraordinary gain and income taxes adjusted for minority interest and undistributed earnings from equity investees. (2) Earnings are deemed to consist of net income to which has been added income taxes (including net deferred investment tax credit), fixed charges and distributed income of equity investees. Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense, and the portion of rental expense which represents an interest factor. Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings which would be required to meet dividend requirements on preferred and preference stock. (3) At December 31, 1999, the company's earnings were deficient by $45.1 million to cover fixed charges.
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/A-2, into the previously filed Registration Statements File Nos. 333-44256, 333-35872, 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. 333-9335, 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, February 1, 2001