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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to _________ Commission File Number 1-3523 Western Resources, Inc. (Exact name of registrant as specified in its charter) Kansas 48-0290150 ------ ---------- (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification Number) 818 South Kansas Avenue Topeka, Kansas 66612 (785) 575-6300 (Address, including zip code and telephone number, including area code, of registrant's principal executive offices) ------------------------------------- Securities registered pursuant to section 12(b) of the Act: Name of each exchange Title of Each Class on which registered ------------------- ----------------------- Common Stock, par value $5.00 per share New York Stock Exchange Securities registered pursuant to section 12(g) of the Act: Preferred Stock, 4-1/2% Series, $100 par value ---------------------------------------------- (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $1,239,059,619 at March 14, 2002. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class Outstanding at March 14, 2002 ----- ----------------------------- Common Stock, par value $5.00 per share 71,415,540 Shares
Documents Incorporated by Reference: Part Document - ---- -------- III The registrant's definitive proxy statement for the Annual Meeting of Shareholders to be held June 11, 2002. 2
TABLE OF CONTENTS Page ---- PART I Item 1. Business.......................................................... 5 Item 2. Properties........................................................ 25 Item 3. Legal Proceedings................................................. 27 Item 4. Submission of Matters to a Vote of Security Holders............... 27 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters........................................................... 28 Item 6. Selected Financial Data........................................... 29 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................. 30 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 60 Item 8. Financial Statements and Supplementary Data....................... 61 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............................................. 111 PART III Item 10. Directors and Executive Officers of the Registrant................ 112 Item 11. Executive Compensation............................................ 114 Item 12. Security Ownership of Certain Beneficial Owners and Management.... 114 Item 13. Certain Relationships and Related Transactions.................... 114 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 115 Signatures................................................................. 120 3
FORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe," "anticipate," "expect," "plan," "will," "may," "could," "estimate," "intend" or words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning: . capital expenditures, . earnings, . liquidity and capital resources, . litigation, . possible corporate restructurings, mergers, acquisitions and dispositions, . compliance with debt and other restrictive covenants, . interest and dividends, . Protection One, Inc.'s financial condition and its impact on our consolidated results, . impairment charges that will be expensed during 2002, . environmental matters, . nuclear operations, . ability to enter new markets successfully and capitalize on growth opportunities in non-regulated businesses, . events in foreign markets in which investments have been made and . the overall economy of our service area. What happens in each case could vary materially from what we expect because of such things as: . electric utility deregulation, . ongoing municipal, state and federal activities, such as the Wichita municipalization effort, . future economic conditions, . changes in accounting requirements and other accounting matters, . changing weather, . rate and other regulatory matters, including the impact of the order to reduce our rates issued on July 25, 2001 by the Kansas Corporation Commission and the impact of the Kansas Corporation Commission's order issued July 20, 2001 and related proceedings, with respect to the proposed separation of Western Resources, Inc.'s electric utility businesses from Westar Industries, Inc., . the impact on our service territory of the September 11, 2001 terrorist attacks, . the impact of Enron Corp.'s bankruptcy on the market for trading wholesale electricity, . political, legislative and regulatory developments, . amendments or revisions to our current business and financial plans, . the consummation of the acquisition of the electric operations of Western Resources, Inc. by Public Service Company of New Mexico and related litigation, . regulatory, legislative and judicial actions, . regulated and competitive markets and . other circumstances affecting anticipated operations, sales and costs. These lists are not all-inclusive because it is not possible to predict all possible factors. See "Item 1. Business -- Risk Factors" for additional information on matters that could impact our expectations. Any forward-looking statement speaks only as of the date such statement was made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made. 4
PART I ITEM 1. BUSINESS GENERAL Western Resources, Inc. is a publicly traded consumer services company incorporated in 1924 in the State of Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the company," "Western Resources," "we," "us," "our" or similar words are to Western Resources, Inc. and its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 640,000 customers in Kansas and monitored security services to over 1.2 million customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an approximate 45% ownership interest, provides natural gas transmission and distribution services to approximately 1.4 million customers in Oklahoma and Kansas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612. We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service using the name Westar Energy. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly traded, approximately 87%-owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns approximately a 99.8% interest. SIGNIFICANT BUSINESS DEVELOPMENTS PNM Transaction - --------------- On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters. On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement 5
was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely. KCC Rate Cases - -------------- On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25 and September 5, 2001, the KCC issued orders that reduced our combined electric rates by $15.7 million. We appealed these orders to the Kansas Court of Appeals, but the KCC orders were upheld. We are evaluating whether to appeal the decision to the Kansas Supreme Court. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Summary of Significant Items -- KCC Rate Cases" for further discussion. KCC Proceedings and Orders - -------------------------- The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance 6
indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect our results of operations. The Financial Plan - ------------------ The July 20, 2001 KCC order directed us to present a financial plan to the KCC. We presented a financial plan to the KCC on November 6, 2001, which we amended on January 29, 2002. The principal objective of the financial plan is to reduce our total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that we will proceed with a rights offering and that, in the event that the PNM merger and related split-off do not close, we will use our best efforts to sell our share of Westar Industries common stock, or shares of our common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. We are unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take. The financial plan provides that: . Westar Industries will use its best efforts to sell at least 4.14 million shares of its common stock, representing approximately 5.1% of its outstanding shares, but no more than the number of shares of its common stock (approximately 19.13 million shares) representing 19.9% of its outstanding shares. After the offering, we would continue to own 77.0 million shares representing between 80.1% and 94.9% of Westar Industries' outstanding shares. The offering will remain open for no less than 45 calendar days. . In the rights offering, each of our shareholders will receive the right to purchase one share of Westar Industries' common stock for every three shares of our stock held on the record date of the offering. There will be no over-subscription privilege in the offering. However, each shareholder participating in the offering will be issued, with respect to each right exercised in the offering, a warrant to purchase from Westar Industries two shares of its common stock at the subscription price in the offering, subject to proration so that in no event will we hold less than 80.1% of Westar Industries' outstanding shares. This right will be exercisable at any time in the 30-day period preceding January 31, 2003. . So long as we and Westar Industries are tax consolidated, Westar Industries' common stock sold in the offering will have one vote per share and Westar Industries common stock held by us will have 10 votes per share. Any shares sold by us will automatically convert to shares with one vote per share. . The exercise price in the offering will be a fixed price determined on the day the offer is mailed to shareholders by calculating the "Westar Industries Valuation" as set forth in an exhibit to the plan and then applying a 10% initial public offering discount. . Westar Industries will have a rescission right through December 31, 2002. This will give Westar Industries the right to repurchase the shares sold in the rights offering at a price equal to the greater of (i) 1.05 times the exercise price, or (ii) the market price at the time of the repurchase offer. The warrants issued to participating shareholders in the offering will expire if the rescission right is exercised. We would not be able to sell any additional shares prior to the expiration of the rescission period. . The proceeds from the offering (or any other subsequent sale of stock by Westar Industries) and any dividends from the ONEOK common or convertible preferred stock not used in Westar Industries' business or previously committed will be used to purchase in the market our or KGE's currently outstanding debt securities. On February 10, 2003, such debt securities and the balance, if any, of our intercompany payable with Westar Industries will be converted into our common stock at the average trading price for the 20 days prior to conversion, but in no event less than $24 per share. However, if the PNM transaction is not terminated, such funds and the intercompany payable will be transferred by us to Westar Industries to purchase 7.5% Western Resources convertible preferred stock, convertible into our common stock at $30 per share, as provided in the PNM merger agreement. Prior to tax 7
deconsolidation, Westar Industries cannot receive any cash dividends from us, but will instead reinvest those dividends in additional shares of our common stock. Dividends on the convertible preferred stock will be payable in additional preferred shares rather than cash. Westar Industries will use interest received on our and KGE debt securities it purchases as provided above to purchase additional debt securities. . If the PNM transaction is not terminated, the amount of our convertible preferred stock purchased by Westar Industries will not exceed $291 million. Westar Industries will continue to own our common stock it currently owns. Westar Industries will retain its option to purchase Westar Generating, Inc., a wholly owned subsidiary of ours, which owns an interest in the State Line Facility (see "Item 2. Properties" for a description of this facility and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Related Party Transactions" for a discussion of this purchase option). . Westar Industries will not vote any of our common stock it owns as long as we are tax consolidated. . Westar Industries will adopt a "poison pill" that will restrict ownership in it to 20% of the shares not owned by us. . The rights offering and subsequent sale of Westar Industries' shares by us pursuant to the plan do not constitute a change in control for our employees under the terms of existing agreements and no agreements will be executed which include a provision under which the offering and sale of Westar Industries' shares by us pursuant to the plan would constitute a change in control. . We will not sell more than 19.9% of Westar Industries unless we have $1.8 billion or less in short- and long-term debt and all of our and KGE's first mortgage bonds are rated investment grade. . In the event Westar Industries' common stock trades for 45 consecutive trading days at a price that is 15% above the price necessary to reduce our short- and long-term debt to an amount less than $1.8 billion (as measured at the end of the immediately preceding fiscal quarter), we will be required to use our best efforts to sell enough shares in Westar Industries, or us, or a combination of both (at our option), to reduce debt to $1.8 billion. However, in no event shall this obligation be triggered prior to February 1, 2003, unless the PNM transaction is terminated prior to that date. Furthermore, on each annual anniversary of the closing of the rights offering, the amount of debt used to determine whether our obligation has been triggered will increase by $100 million. . We agree to reduce our total debt by at least $100 million per year each year following the completion of the offering until the separation is consummated. . Our board of directors will have at least a majority of independent directors following the separation. Impairment Charge Pursuant to New Accounting Rules - -------------------------------------------------- Effective January 1, 2002, we adopted Statement of Financial Accounting Standard (SFAS) No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," which together establish new standards for accounting for goodwill and other long-lived assets. Pursuant to these new standards, we will record an impairment charge to write down goodwill and customer accounts to their estimated fair values in the first quarter of 2002. The amount of this charge, net of tax, will be approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. For further information on the impairment charge, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Summary of Significant Items -- Impairment Charge Pursuant to New Accounting Rules." 8
Ice Storm - --------- In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. ELECTRIC UTILITY OPERATIONS General - ------- We supply electric energy at retail to approximately 640,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We also supply electric energy at wholesale to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we have power marketing operations which purchase and sell electricity in areas outside of our historical marketing territory. Our electric sales for the years ended December 31, 2001, 2000 and 1999 were as follows: 2001 2000 1999 ---------- ---------- ---------- (In Thousands) Residential .......................... $ 419,492 $ 452,674 $ 407,371 Commercial ........................... 380,277 367,367 356,314 Industrial ........................... 244,392 252,243 251,391 Wholesale and Interchange ............ 233,129 214,721 174,895 Power Marketing ...................... 408,242 457,178 190,101 System Marketing ..................... 32,192 35,321 3,320 Other ................................ 50,669 49,629 46,306 ---------- ---------- ---------- Total ........................... $1,768,393 $1,829,133 $1,429,698 ========== ========== ========== The following table reflects electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No amounts are included for power marketing and system marketing sales because these sales are not based on electricity we generate. 2001 2000 1999 ------ ------ ------ (Thousands of MWh) Residential .......................... 5,755 6,222 5,551 Commercial ........................... 6,742 6,485 6,202 Industrial ........................... 5,617 5,820 5,743 Wholesale and Interchange ............ 7,547 6,892 5,617 Other ................................ 107 108 108 ------ ------ ------ Total ........................... 25,768 25,527 23,221 ====== ====== ====== Generation Capacity - ------------------- The aggregate net generating capacity of our system is presently 5,947 megawatts (MW). The system has interests in 21 fossil-fuel steam generating units, one combined cycle steam generating unit, one nuclear generating unit, ten combustion peaking turbines, two combined cycle combustion turbines, two diesel generators and two wind generators. Our aggregate 2001 peak system net load of 4,468 MW occurred on July 30, 2001. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 19% above 9
system peak responsibility at the time of the peak. Our all time peak system net load of 4,528 MW occurred on September 11, 2000. We have a market-based rate authority from the FERC, under which we buy and sell energy and capacity throughout the United States. We have agreed to provide generating capacity to other utilities for certain periods as set forth below: Utility Capacity (MW) Period Ending ------------------------------------------- ------------- ------------- Oklahoma Municipal Power Authority (OMPA).................................... 60 December 2013 Midwest Energy, Inc........................ 60 May 2008 125 May 2010 Empire District Electric Company (Empire).. 80 May 2001 162 May 2010 McPherson Board of Public Utilities (McPherson)................................ (a) May 2027 --------- (a) We provide base capacity to McPherson. McPherson provides peaking capacity to us. During 2001, we provided approximately 74 MW to and received approximately 182 MW from McPherson. The amount of base capacity provided to McPherson is based on a fixed percentage of McPherson's annual peak system load. We forecast that we will need additional generating capacity of approximately 150 MW by 2006 to serve our customers' expected electricity needs. We will determine how to meet this need at a future date. Fossil Fuel Generation - ---------------------- Fuel Mix: Coal-fired units comprise 3,349 MW of our total 5,947 MW of generating capacity and the nuclear unit provides 550 MW of capacity. Of the remaining 2,048 MW of generating capacity, units that can burn either natural gas or oil account for 1,964 MW, units that burn only diesel fuel account for 83 MW, and wind turbines account for approximately 1 MW (see "Item 2. Properties"). Based on MMBtus burned, the 2001 and estimated 2002 fuel mix (percent of electricity produced by a specific fuel type) are as follows: Estimated Fuel 2001 2002 ---- ---- ---- Coal..................................... 77% 78% Nuclear.................................. 17% 15% Gas, Oil or Diesel Fuel.................. 6% 7% Our fuel mix fluctuates with the operation of the nuclear-powered Wolf Creek (as discussed below under "-- Nuclear Generation"), fuel costs, plant availability and power available on the wholesale market. Coal: Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center --------------------- (JEC) have an aggregate capacity of 1,860 MW (our 84% share). We have a long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company, to supply coal to JEC from mines located in the Powder River Basin in Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual MMBtu delivery quantities. The coal to be supplied is surface mined and has an average Btu content of approximately 8,407 Btu per pound and an average sulfur content of 0.43 lbs/MMBtu (see "-- Environmental Matters"). The average cost of coal burned at JEC during 2001 was approximately $1.10 per MMBtu, or $18.57 per ton. 10
Coal is transported from Wyoming under a long-term rail transportation contract with Burlington Northern Santa Fe (BNSF) and Union Pacific (UP) railroads with a term continuing through December 31, 2013. LaCygne Generating Station: The two coal-fired units at LaCygne Station -------------------------- have an aggregate generating capacity of 681 MW (KGE's 50% share). LaCygne 1 uses a blended fuel mix containing approximately 85% Powder River Basin coal and 15% Kansas/Missouri coal. LaCygne 2 uses Powder River Basin coal. The operator of LaCygne Station, Kansas City Power and Light Company (KCPL), administers the coal and coal transportation contracts. A portion of the LaCygne 1 and LaCygne 2 Powder River Basin coal is supplied through several fixed price and spot market contracts that expire at various times through 2003 and is transported under KCPL's Omnibus Rail Transportation Agreement with BNSF and Kansas City Southern Railroad through December 31, 2010. Additional coal may be acquired on the spot market. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers. The Powder River Basin coal supplied during 2001 had an average Btu content of approximately 8,527 Btu per pound and an average sulfur content of 0.73 lbs/MMBtu. During 2001, the average cost of all coal burned at LaCygne 1 was approximately $0.86 per MMBtu, or $14.88 per ton. The average cost of coal burned at LaCygne 2 was approximately $0.79 per MMBtu, or $13.47 per ton. Lawrence and Tecumseh Energy Centers: The coal-fired units located at the ------------------------------------ Tecumseh and Lawrence Energy Centers have an aggregate generating capacity of 808 MW. In 2001, we obtained coal from Wyoming and Colorado. The Wyoming coal supplied in 2001 had an average Btu content of approximately 8,753 Btu per pound and an average sulfur content of 0.46 lbs/MMBtu. The Colorado coal supplied in 2001 had an average Btu content of approximately 11,030 Btu per pound and an average sulfur content of 0.44 lbs/MMBtu. During 2001, the average cost of all coal burned in the Lawrence units was approximately $1.25 per MMBtu, or $25.19 per ton. The average cost of all coal burned in the Tecumseh units was approximately $1.22 per MMBtu, or $23.76 per ton. The Wyoming Powder River Basin coal is transported by BNSF railroad and the Colorado coal is transported by BNSF and UP railroads. We have Wyoming coal under contract to support the anticipated operation of these units through the end of 2004. We have a portion of our Wyoming coal needs under a contract that expires in 2004. We may also purchase coal on the spot market. General: We have entered into all of our coal contracts in the ordinary ------- course of business and do not believe we are substantially dependent upon these contracts. We believe there are other suppliers with plentiful sources of coal available at spot market prices to replace, if necessary, fuel to be supplied pursuant to these contracts. In the event that we were required to replace our coal agreements, we would not anticipate a substantial disruption of our business although the cost of purchasing coal could increase. We have entered into all of our coal transportation contracts in the ordinary course of business. Several rail carriers are capable of serving the coal mines from where our coal originates, but several of our generating stations can be served by only one rail carrier. In the event the rail carrier to one of our generating stations fails to provide reliable service, we could experience a short-term disruption of our business. However, due to the obligation of the rail carriers to provide service under the Interstate Commerce Act, we do not anticipate any substantial long-term disruption of our business although the cost of transporting coal could increase. Natural Gas: We use natural gas as a primary fuel in our Gordon Evans, Murray Gill, Neosho, Abilene, and Hutchinson Energy Centers, in the gas turbine units at our Tecumseh generating station and in the combined cycle units at the State Line facility. 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 supplies the system with the flexible natural gas supply as necessary to meet operational needs. For Abilene and Hutchinson Energy Centers, we maintain natural gas transportation with Kansas Gas Service Company, a division of ONEOK, under a contract that expires April 30, 2004. For Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers, we meet a portion of our natural gas transportation 11
requirements through firm natural gas transportation capacity agreements with Williams Gas Pipelines Central. All of the natural gas transportation requirements for the State Line facility are met through a firm natural gas transportation agreement with Williams Gas Pipelines Central. The firm transportation agreements that serve Gordon Evans, Murray Gill, Lawrence and Tecumseh extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016. 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 some of our generating stations and as a primary fuel in the Hutchinson No. 4 combustion turbine and in the diesel generators. Oil is obtained by spot market purchases and year-long contracts. We maintain quantities in inventory to meet emergency requirements and protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to burn. Other Fuel Matters: Our contracts to supply fuel for our coal-fired and natural gas-fired generating units, with the exception of JEC, do not provide full fuel requirements at the various stations. Supplemental fuel is procured on the spot market to provide operational flexibility and to take advantage of economic opportunities when the price is favorable. We use financial instruments to hedge a portion of our anticipated fossil fuel needs in an attempt to offset the volatility of the spot market. Due to the volatility of these markets, we are unable to determine what the value of these financial instruments will be when the agreements are actually settled. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information - -- Market Risk Disclosure" for further information. The table below provides information relating to the weighted average cost of fuel that we have used (which includes the commodity cost, transportation cost to our facilities and any other associated costs). 2001 2000 1999 ------- ------- ------- KPL Plants ---------- Per Million Btu: Coal .......................... $ 1.15 $ 1.13 $ 1.09 Gas ........................... 4.61 3.84 2.66 Oil ........................... 3.99 3.45 4.17 Per MWh Generation ............... $ 13.92 $ 13.61 $ 12.57 KGE Plants ---------- Per Million Btu: Nuclear ....................... $ 0.44 $ 0.44 $ 0.45 Coal .......................... 0.95 0.91 0.87 Gas ........................... 3.75 3.34 2.31 Oil ........................... 3.84 3.12 2.11 Per MWh Generation ............... $ 11.04 $ 11.08 $ 9.83 Nuclear Generation - ------------------ Fuel Supply: The owners of Wolf Creek have on hand or under contract 100% of their uranium and uranium conversion needs for 2002 and 77% of the uranium and uranium conversion required for operation of Wolf Creek through October 2006. The balance is expected to be obtained through spot market and contract purchases. The owners have under contract 100% of Wolf Creek's uranium enrichment needs for 2002 and 90% of the uranium enrichment required to operate Wolf Creek through October 2006. The balance of Wolf Creek's enrichment needs are expected to be obtained through spot market and contract purchases. 12
All uranium, uranium conversion and uranium enrichment arrangements have been entered into in the ordinary course of business, and Wolf Creek is not substantially dependent upon these agreements. Despite contraction and consolidation in the supply sector for these commodities and services, Wolf Creek's management believes there are other supplies available to replace, if necessary, these contracts. In the event these contracts were required to be replaced, Wolf Creek's management does not anticipate a substantial disruption of Wolf Creek's operations. Nuclear fuel is amortized to cost of sales based on the quantity of heat produced (MMBtus) for the generation of electricity. Radioactive Waste Disposal: Under the Nuclear Waste Policy Act of 1982 (NWPA), the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales. In 1996 and 1997, a U.S. Court of Appeals issued decisions that (1) the NWPA unconditionally obligated the DOE to begin accepting spent fuel for disposal in 1998 and (2) precluded the DOE from concluding that its delay in accepting spent fuel is "unavoidable" under its contracts with utilities due to lack of a repository or interim storage authority. In May 1998, the Court issued an order in response to the utilities' petitions for remedies for DOE's failure to begin accepting spent fuel for disposal. The Court affirmed its conclusion that the sole remedy for DOE's breach of its statutory obligation under the NWPA is a contract remedy and indicated that the Court will not revisit the matter until the utilities have completed their pursuit of that remedy. Wolf Creek intends to pursue its claims against the DOE. A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025. The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that the various states, individually or through interstate compacts, develop alternative low-level radioactive waste disposal facilities. The states of Kansas, Nebraska, Arkansas, Louisiana and Oklahoma formed the Central Interstate Low-Level Radioactive Waste Compact (Compact) and selected a site in Nebraska to locate a disposal facility. WCNOC and the owners of the other five nuclear units in the Compact have provided most of the pre-construction financing for this project. Our net investment in the Compact through December 31, 2001 was approximately $7.4 million. On December 18, 1998, the Nebraska agencies responsible for considering the developer's license application denied the application. The license applicant has sought a hearing on the license denial, but a U.S. District Court has indefinitely delayed proceedings related to the hearing. In December 1998, most of the utilities that had provided the project's pre-construction financing (including WCNOC) filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application. Shortly thereafter, the Central Interstate Low-Level Radioactive Waste Commission (Commission) (responsible for causing a new disposal facility to be developed within the Compact region) and US Ecology (the license applicant) filed similar claims against Nebraska. In September 1999, the U.S. District Court partially denied and partially granted Nebraska's motions to dismiss the utilities' and US Ecology's cases and denied Nebraska's motion to dismiss the Commission's case. Since that time, the utilities have dismissed their remaining claims against Nebraska for monetary damages, but their claims for equitable relief remain. The Commission's claims for monetary damages and equitable relief also remain, and the parties expect the case to go to trial in the second half of 2002. 13
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. Outages: Wolf Creek has an 18-month refueling and maintenance schedule which permits uninterrupted operation every third calendar year. An outage began on March 23, 2002. During the outage, electric demand is expected to be met primarily by our other fossil-fueled generating units and by purchased power. An extended shut-down of Wolf Creek could have a substantial adverse effect on our business, financial condition and results of operations because of higher replacement power and other costs. Although not expected, reacting to safety issues, the Nuclear Regulatory Commission (NRC) could impose an unscheduled plant shut-down due to terrorist or other concerns. Customer Operations - ------------------- Our Customer Operations segment transports electricity from the generating stations to approximately 640,000 customers in Kansas. It also transports electric energy to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. Customer Operations properties include substations, poles, wire, underground cable systems, and customer meters. Customer Operations' objective is to provide low-cost electricity transportation while maintaining a high level of system reliability and customer service. We are a member of the Southwest Power Pool (SPP). In February 2002, SPP and the Midwest Independent System Operator, Inc. (MISO) executed a definitive agreement for the consolidation of the two organizations, which is expected to occur in 2003. We anticipate that after the consolidation of SPP and MISO, we will participate in MISO. Among other things, these organizations were formed to maintain transmission system reliability on a regional basis. See "--Competition and Deregulation" below for more information on these organizations. We are also a member of the SPP transmission tariff, along with ten other transmission providers in the region. Revenues from this tariff are divided among the tariff members based upon calculated impacts to their respective systems. The tariff allows for both firm and non-firm transmission access. We will file a new transmission tariff with MISO as it becomes operational. Customer Operations also includes the customer service portion of our electric utility business. Customer service includes, among other things, operating our phone center, handling credit and collections, billing, meter reading and field service. Security and Insurance - ---------------------- We have increased the level of security measures at our generation facility sites and various offices, in part due to nationwide terrorist concerns. These measures include, but are not limited to, increased security personnel, utilization of armed guard services, patrolling of company property, restricting access to our properties and implementing emergency training and response procedures. Wolf Creek's management has increased both voluntary and federally-mandated security measures at Wolf Creek. The NRC has required nuclear power plants to be operated at the highest level of security since September 14
11, 2001. The measures implemented at Wolf Creek include, but are not limited to, increased guard service, no unscheduled public visits and emergency training and response procedures. The NRC has issued orders to all nuclear plants that make our current voluntary security measures mandatory. The orders also impose new security requirements at U.S. nuclear power plants. Wolf Creek's security costs will increase as a result of these orders. In addition, there are unfavorable trends in the availability and price of property and casualty insurance primarily due to catastrophic events and the world's financial markets. We anticipate material increases in insurance costs, although the amount of the increase is unknown at this time. Information with respect to insurance coverage applicable to the operations of our nuclear generating facility is set forth in Note 14 of the "Notes to Consolidated Financial Statements." Competition and Deregulation - ---------------------------- Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000. In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self-generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our rates range from approximately 10% to 20% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment. Increased competition for retail electricity sales may in the future reduce our earnings, which could impact our ability to pay dividends and could have a material adverse impact on our operations and our financial condition. A material non-cash charge to earnings may be required should we discontinue accounting under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." 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 to use their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power. After the FERC rejected several attempts by the SPP to seek RTO status, the SPP and MISO agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations. 15
For further discussion regarding competition and its potential impact on us, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Electric Utility." Regulation and Rates - -------------------- As a Kansas electric utility, we are subject to the jurisdiction of the KCC, which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts and various other matters. We are also subject to the jurisdiction of the KCC and FERC with respect to the issuance of certain securities. The NRC regulates our nuclear operations. Additionally, we are subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of certain securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. 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). On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a $41.2 million reduction in KGE's rates and an $18.5 million increase in our rates. On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court. Additional information with respect to rate matters and regulation is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Summary of Significant Items -- KCC Rate Cases," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Electric Utility" and Notes 2 and 3 of "Notes to Consolidated Financial Statements." Environmental Matters - --------------------- We currently hold all federal and state environmental approvals required for the operation of all of our generating units. We believe we are presently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide and nitrogen oxides (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA). The JEC and LaCygne 2 units have met: (1) the federal sulfur dioxide standards through the use of low sulfur coal; (2) the federal particulate matter standards through the use of electrostatic precipitators; and (3) the federal NOx standards through boiler design and operating procedures. The JEC units are also equipped with flue gas scrubbers providing additional sulfur dioxide and particulate matter emission reduction capability when needed to meet permit limits. The Kansas Department of Health and Environment (KDHE) regulations applicable to our other generating facilities prohibit the emission of more than 3.0 pounds of sulfur dioxide per MMBtu of heat input. We meet these standards through the use of low sulfur coal and by all coal-burning facilities being equipped with flue gas scrubbers and/or electrostatic precipitators. 16
We must comply, and are currently in compliance, with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II sulfur dioxide and nitrogen oxide requirements. All of our generating facilities are in substantial compliance with the Best Practicable Technology and Best Available Technology regulations issued by the EPA pursuant to the Clean Water Act of 1977. Most EPA regulations are administered in Kansas by the KDHE. Additional information with respect to Environmental Matters is discussed in Note 14 of the "Notes to Consolidated Financial Statements." MONITORED SERVICES OPERATIONS General - ------- We provide property monitoring services through Protection One and Protection One Europe to approximately 1.2 million customers in North America and approximately 62,000 customers in continental Europe. Revenues are generated primarily from recurring monthly payments for monitoring and maintaining the alarm systems that are installed in customers' homes and businesses. Services are provided to residential (both single family and multifamily residences), commercial and wholesale customers. Currently, North America's customers are primarily in the residential market and Europe's customers are primarily in the commercial market. In prior years, the strategy for the monitored security business was focused primarily on growing the customer account base to achieve critical mass. Protection One and Protection One Europe grew rapidly by participating in the growth in the alarm industry and by acquiring other alarm companies. The strategic focus has now shifted to improving returns on invested capital by realizing economies of scale from increasing customer density in the largest urban markets in North America. Protection One plans to accomplish this goal by: . retaining customers by providing superior customer service from monitoring facilities and branches; . using its national presence, strategic alliances, and strong local operations to persuade the most desirable residential and commercial prospects to enter into long term agreements with it on terms that permit it to achieve appropriate returns on capital; and . on a limited basis in 2002 or 2003, acquiring alarm companies and portfolios of alarm accounts pursuant to transactions that meet strategic and financial requirements. Operations - ---------- Monitored services operations consist principally of alarm monitoring, customer service functions and branch operations. Security alarm systems include many different types of devices installed on customers' premises designed to detect or react to various occurrences or conditions, such as intrusion or the presence of fire or smoke. Products range from basic intrusion and fire detection equipment to fully integrated systems with card access, closed circuit television and voice/video monitoring. Alarm monitoring customer contracts generally have initial terms ranging from two to ten years in duration, and provide for automatic renewals for a fixed period (typically one year) unless one of the parties elects to cancel the contract at the end of its term. 17
Protection One provides monitoring services from six monitoring facilities in North America. Protection One Europe provides monitoring services from facilities in Paris and Vitrolles, France. See "Item 2. Properties" for further information. In 2001, Protection One substantially completed the installation of the technology platform referred to as MAS(R), or Monitored Automation Systems, that combines the customer service, monitoring, billing, and collection functions into a single system. The conversion to MAS(R) has enabled Protection One to consolidate monitoring facilities, resulting in operational efficiencies and cost savings. Conversion of the Portland, Maine monitoring facility was completed in January 2002. Currently, approximately 94% of Protection One's North America residential and commercial customer base is served by MAS(R). Branch Operations - ----------------- Protection One maintains approximately 60 service branches in North America from which it provides field repair, customer care, alarm response and sales services and seven satellite locations from which it provides field repair services. Protection One Europe maintains approximately 35 sales branch offices in continental Europe, primarily in France. Customer Acquisition Strategy - ----------------------------- Protection One's current customer acquisition strategy for North America relies primarily on internally generated sales. In June 2001, Protection One notified most of its remaining domestic dealers that it was terminating its dealer arrangements with them and therefore would not be extending or renewing their contracts. The number of accounts Protection One purchased through its dealer program decreased from 21,817 in 2000 to 7,501 in 2001. Protection One currently has a salaried and commissioned sales force that utilizes its existing branch infrastructure in approximately 60 markets. In late 2001, Protection One entered into a marketing alliance with BellSouth Telecommunications, Inc. to expand its residential, single-family market. Protection One's multifamily business utilizes a salaried and commissioned sales force to produce new accounts. It markets its services and products primarily to developers, owners and managers of apartment complexes and other multifamily dwellings. Protection One grows its multifamily business through national and regional advertising, nationwide professional field sales efforts, centralized inbound and outbound sales functions, prospective acquisition marketing efforts and professional industry-related association affiliation. Protection One continually evaluates its customer creation and marketing strategy, including evaluating each respective channel for economic returns, volume and other factors and may shift its strategy or focus, including the elimination of a particular channel. Protection One Europe's customer acquisition strategy also relies primarily on internally generated sales. Protection One Europe uses an internal sales force of approximately 300 employees, which operate out of 35 branch locations in France, Germany, Belgium and the Netherlands. Protection One Europe's salary structure for its internal sales force is heavily reliant on commissions, but contains a portion of fixed salaries. In addition, Protection One Europe owns a telemarketing company, known as Eurocontact, which provides qualified leads to the sales network. 18
Competition - ----------- The security alarm industry is highly competitive. In North America, there are only four 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 total annual revenues in 2000, Protection One believes the top four alarm companies in North America are: . ADT Security Services, a subsidiary of Tyco International, Ltd. (ADT) . Protection One . Brinks Home Security Inc., a subsidiary of The Pittston Services Group of North America . Honeywell Inc. In continental Europe, there are a large number of small competitors and a few large regional competitors who have recently been taking steps toward establishing a continental presence. The large regional competitors include the following companies: . CIPE, a subsidiary of ADT Security Services and Tyco International, Ltd., which is the largest security company in France . Chubb, a United Kingdom based company which is also a leading security company in France . Securitas, based in Sweden, which has its principal operations in the guarding industry but is expanding operations in monitored security . Group 4 Falck, a Danish security company that has significant operations in Scandinavia and has recently expanded into Germany and the Netherlands . Rentokil Initial, based in the Netherlands which has established operations in France and the United Kingdom Competition in the security alarm industry is based primarily on market visibility, price, reputation for quality of services and systems, services offered and the ability to identify and to solicit prospective customers as they move into homes and businesses. Protection One and Protection One Europe believe that they compete effectively with other national, regional and local security alarm companies due to their ability to offer integrated alarm system installation, monitoring, repair and enhanced services, their reputation for reliable equipment and services and their prominent presence in the areas surrounding their branch offices. Competitors exist in the market that have greater financial resources than Protection One or Protection One Europe, enabling them to offer higher prices to purchase customer accounts. The effect of such competition may be to reduce the growth of our customer account base as purchase opportunities may be limited by our available resources. 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. . Requiring permits for individual alarm systems and revoking 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. Monitored services 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 and Protection One Europe are 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. 19
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 monitoring services 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 jurisdictions in which Protection and Protection One Europe operate also regulate such practices. Such laws and regulations include restrictions on the manner in which the sale of security alarm systems is promoted, 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. The 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 foreign jurisdictions in which Protection One and Protection One Europe operate regulate the telephone communications with the local authorities. Risk Management - --------------- The nature of providing monitored services potentially exposes Protection One and Protection One Europe to greater risks of liability for employee acts or omissions, or system failure, than may be inherent in other businesses. Substantially all alarm monitoring agreements, and other agreements, pursuant to which products and services are sold, contain provisions limiting liability to customers in an attempt to reduce this risk. Protection One and Protection One Europe carry insurance of various types, including general liability and errors and omissions insurance in amounts considered adequate and customary for the industry and business. Loss experience, and the loss experiences at other security services companies, may affect the availability and cost of such insurance. Certain insurance policies, and the laws of some states and countries, may limit or prohibit insurance coverage for punitive or certain other types of damages, or liability arising from gross negligence. SEGMENT INFORMATION Financial information with respect to business segments is set forth in Note 24 of the "Notes to Consolidated Financial Statements." GEOGRAPHIC INFORMATION Geographic information is set forth in Note 24 of the "Notes to Consolidated Financial Statements." EMPLOYEES As of February 28, 2002, we had approximately 5,600 employees, of which approximately 3,700 were employees of Protection One and Protection One Europe. In the fourth quarter of 2001 and in January 2002, we reduced our utility work force by approximately 600 employees through involuntary and voluntary separation programs. We may replace some of these employees. Protection One reduced its work force by approximately 700 employees in 2001 and in January and February 2002 due to facility consolidations and other cost cutting measures. We did not experience any strikes or work stoppages during 2001. Our current contract with the International Brotherhood of Electrical Workers extends through June 30, 2002. The contract covers approximately 1,100 employees as of February 28, 2002. We are currently negotiating an extension of the contract. 20
RISK FACTORS You should read the following risk factors in conjunction with discussions of factors discussed elsewhere in this and other of our filings with the Securities and Exchange Commission (SEC). These cautionary statements are intended to highlight certain factors that may affect our financial condition and results of operations and are not meant to be an exhaustive discussion of risks that apply to public companies with broad operations, such as us. Like other businesses, we are susceptible to macroeconomic downturns in the United States or abroad that may affect the general economic climate and our performance or that of our customers. Similarly, the price of our securities is subject to volatility due to fluctuations in general market conditions, differences in our results of operations from estimates and projections generated by the investment community and other factors beyond our control. We Are a Public Utility Subject to Regulation Which Significantly Impacts Our Business, Results of Operations, Financial Position and Prospects: We are regulated by the KCC and FERC and other federal and state agencies. See "-- Electric Utility Operations -- Regulation and Rates." This regulation impacts most aspects of our business and operations. Throughout this Annual Report on Form 10-K, we have described the impact of regulation and the significant effect it has on our business, financial condition, results of operations, liquidity and prospects. Such regulation is impacted by matters beyond our control, such as general economic conditions, politics and competition, and other matters described under "Forward-Looking Statements." We refer you to "-- Significant Business Developments," and the other risk factors below, as well as "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," for a further discussion of some of the more important matters which are currently the subject of, or related to, regulatory concerns. Municipalization Efforts by Wichita May Affect Operations and Results: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 23% of our total energy sales. Fuel and Purchased Power Costs are Included in Retail Rates at a Fixed Level and Increases are not Recovered Automatically: Fuel and purchased power costs are recovered in retail rates at a fixed test year level. Therefore, to recover fuel and purchased power costs in excess of the costs built into retail rates, we would have to make a rate filing with the KCC, which could be denied in whole or in part. During 2001, we entered into a gas hedging arrangement, designed to eliminate a portion of our risk through July 2004. Any increase in fuel and purchased power costs over the costs recovered through rates would reduce our earnings. Increases could be material. 21
Purchased Power Commodity Prices are Volatile: The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to fluctuating market prices that may adversely impact our financial position and results of operations. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition. Hedging and Trading Activities Involve Risks: We are involved in hedging and trading activities primarily to minimize risk from commodity market fluctuations, capitalize on market knowledge and enhance system reliability. In these activities, we utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, futures, options and swaps providing for payments (or receipt of payments) from counterparties based on the differential between the contract price and a specified index price. Our hedging and trading activities involve risks, including commodity price risk, interest rate risk and credit risk. Commodity price risk is the risk that changes in commodity prices may impact the price at which we are able to buy and sell electricity and purchase fossil fuels for our generators. These commodities have experienced price volatility in the past and can be expected to do so in the future. This volatility may increase or decrease future earnings. Interest rate risk is the risk of loss associated with movements in market interest rates. Our exposure to interest rate risk is limited due to the fixed-rate nature of most of our long-term debt. During 2001, we utilized an interest rate swap to manage our exposure to variable interest rates. The swap converted $500 million of variable rate debt to a fixed rate. In the future, we may continue to utilize swaps or other financial instruments to manage interest rate risk. Credit risk is the risk of loss resulting from non-performance by a counterparty of its contractual obligations. As we continue to expand our power marketing and commodity trading activities, our exposure to credit risk and counterparty default may increase. We maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. We employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. See " Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Market Risk Disclosure" for further discussion. Results actually achieved from these activities could vary materially from intended results and could materially affect our financial results. Current Levels of Debt Could Adversely Affect Our Business: We have a large amount of consolidated indebtedness. As of December 31, 2001, we had outstanding total indebtedness of approximately $3.4 billion, of which approximately $2.9 billion was the obligation of our Westar Energy operations. A large amount of indebtedness could have a negative impact on, among other things, our ability to obtain additional financing in the future for working capital, capital expenditures and general corporate purposes and our ability to withstand a downturn in our business or the economy in general. The indentures governing our long-term indebtedness require us to satisfy certain financial conditions in order to borrow additional funds. These covenants require, among other things, that we maintain certain leverage and interest coverage ratios. We are in compliance with these covenants. A breach of any of the covenants could 22
result in an event of default, which would allow the lenders to declare all amounts outstanding immediately due and payable. For information regarding a financial plan that was filed with the KCC that details our current plans for debt reduction, see "-- Significant Business Developments -- KCC Proceedings and Orders" and "-- Significant Business Developments -- The Financial Plan" above. Strategic Transactions May Not Be Completed: Our strategic plans include the acquisition of our electric utility businesses by PNM and the split-off of Westar Industries to our shareholders. Prior to the completion of these transactions, Westar Industries would sell a portion of its common stock in a rights offering to our shareholders. The completion of these transactions is subject to the satisfaction of various conditions, including the receipt of shareholder and regulatory approvals in the case of the PNM transaction. We believe the completion of the proposed transaction with PNM is not likely. See "-- Significant Business Developments -- PNM Transaction" above for more information. The Separation of Westar Industries Would Impact Results of Operations: The financing plan we have filed with the KCC proposes a rights (and warrants) offering of Westar Industries common stock to our shareholders. The financing plan also contemplates (and in certain circumstances requires) a sale of all, or some of, the Westar Industries common stock we own following the rights (and warrants) offering. If a Westar Industries rights offering is completed, we would record a non-cash charge against income equal to the difference between the book value of the portion of our investment in Westar Industries sold in the rights offering and the offering proceeds received by Westar Industries. Similarly, if a split-off or sale of all or part of Westar Industries were completed, we would record a non-cash charge against income equal to the difference between the book value of our remaining investment in Westar Industries and the fair market value of the shares of Westar Industries common stock distributed to our shareholders or sold. We are unable to determine the amount of the charges at this time because the subscription price in the rights offering has not been determined and the fair market value of the common stock of Westar Industries distributed in the split-off or sale of Westar Industries common stock will be determined at the time it occurs. However, the charges could be material and may have a material adverse effect on our operating results in the period recorded. See "-- Significant Business Developments -- The Financial Plan" above for more information. Monitored Services Has Had a History of Losses which are Likely to Continue: Our monitored services segment incurred losses before interest and taxes of $126.1 million in 2001, $91.4 million in 2000 and $20.7 million in 1999. These losses reflect, among other factors: . lower revenues due to a smaller customer base; . substantial charges incurred for amortization of purchased customer accounts and goodwill; . interest incurred on indebtedness; . other charges required to manage operations; and . costs associated with the integration of acquisitions. We anticipate that Protection One will also continue to incur substantial interest expense because of its substantial debt. We do not expect the monitored services segment to attain profitable operations in the foreseeable future. Monitored Services Loses Customers Over Time: Protection One and Protection One Europe experience the loss of accounts, referred to as attrition, as a result of, among other factors, relocation of customers, adverse financial and economic conditions, competition from other alarm service companies, and customer service and operational difficulties with the integration of acquired 23
customers. Prior to 2000, the effects of the gross number of lost customers were offset by a combination of factors that resulted in an overall increase in the number of customers and revenue, including acquiring alarm account portfolios, purchasing accounts from dealers, adding new accounts from customers who moved into premises previously occupied by prior customers in which security alarm systems were installed, adding accounts for which Protection One obtained a guarantee from the seller that allowed Protection One to "put" back to the seller cancelled accounts, and revenues from price increases and the sale of enhanced services. In 2001 and 2000, Protection One's customer acquisition strategies did not replace accounts lost as a result of attrition. This is due primarily to a move from reliance on a dealer program to generate customer accounts to reliance on internally generated sales. The failure of Protection One and Protection One Europe's customer acquisition strategies to increase the number of new accounts, or the inability of Protection One and Protection One Europe to reduce attrition levels, could have a material adverse effect on their businesses, financial conditions and results of operations. Monitored Services Will Record an Impairment Charge in the First Quarter of 2002 and Additional Charges May be Recorded in the Future: In the first quarter of 2002, the monitored services segment will record an impairment charge to write down goodwill and customer accounts to their estimated fair values. The amount of this charge net of tax will be approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. For further information on the impairment charge, see Note 25 of the "Notes to Consolidated Financial Statements." After this write down is recorded, we will still have material amounts of goodwill and customer accounts recorded on our consolidated balance sheet. The remaining amount of goodwill will be required to be tested annually for impairment. Customer accounts will be required to be tested upon certain triggering events, which include recurring operating losses, adverse business conditions, declines in market values and other matters that negatively impact value. If the monitored services segment fails future impairment tests for either goodwill or customer accounts, we will be required to recognize additional impairment charges on these assets in the future. The Impact of Protection One Class Action Litigation May Be Material: We, Westar Industries, Protection One and its subsidiary Protection One Alarm Monitoring, Inc. (Protection One Alarm 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 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, 1998, 1999 and the first three quarters of 2000 were false and misleading. Protection One and we cannot currently predict the impact of this litigation, which could be material. See "Item 3. Legal Proceedings" and Note 16 of the "Notes to Consolidated Financial Statements" for more information. 24
ITEM 2. PROPERTIES - ------------------ ELECTRIC UTILITY FACILITIES - -------------------------------------------------------------------------------------------------------------------------------- Year Principal Unit Capacity Name Unit No. Installed Fuel (MW) Segment - -------------------------------------------------------------------------------------------------------------------------------- Abilene Energy Center: Combustion Turbine 1 1973 Gas 71.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Gordon Evans Energy Center: Steam Turbines 1 1961 Gas--Oil 151.0 Fossil Generation 2 1967 Gas--Oil 383.0 Fossil Generation Combustion Turbines 1 2000 Gas--Oil 80.0 Fossil Generation 2 2000 Gas--Oil 80.0 Fossil Generation 3 2001 Gas--Oil 154.0 Fossil Generation Diesel Generator 1 1969 Diesel 3.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Hutchinson Energy Center: Steam Turbines 1 1950 Gas 17.0 Fossil Generation 2 1950 Gas 16.0 Fossil Generation 3 1951 Gas 31.0 Fossil Generation 4 1965 Gas 175.0 Fossil Generation Combustion Turbines 1 1974 Gas 52.0 Fossil Generation 2 1974 Gas 54.0 Fossil Generation 3 1974 Gas 54.0 Fossil Generation 4 1975 Diesel 77.0 Fossil Generation Diesel Generator 1 1983 Diesel 3.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Jeffrey Energy Center (84%): Steam Turbines 1 (a) 1978 Coal 625.0 Fossil Generation 2 (a) 1980 Coal 612.0 Fossil Generation 3 (a) 1983 Coal 623.0 Fossil Generation Wind Turbines 1 (a) 1999 -- 0.6 Fossil Generation 2 (a) 1999 -- 0.6 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- LaCygne Station (50%): Steam Turbines 1 (a) 1973 Coal 344.0 Fossil Generation 2 (b) 1977 Coal 337.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Lawrence Energy Center: Steam Turbines 3 1954 Coal 57.0 Fossil Generation 4 1960 Coal 119.0 Fossil Generation 5 1971 Coal 388.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Murray Gill Energy Center: Steam Turbines 1 1952 Gas--Oil 43.0 Fossil Generation 2 1954 Gas--Oil 74.0 Fossil Generation 3 1956 Gas--Oil 112.0 Fossil Generation 4 1959 Gas--Oil 107.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Neosho Energy Center: Steam Turbine 3 1954 Gas--Oil 69.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- State Line (40%): Combined Cycle 2-1 (a) 2001 Gas 60.0 Fossil Generation 2-2 (a) 2001 Gas 60.0 Fossil Generation 2-3 (a) 2001 Gas 80.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Tecumseh Energy Center: Steam Turbines 7 1957 Coal 86.0 Fossil Generation 8 1962 Coal 158.0 Fossil Generation Combustion Turbines 1 1972 Gas 20.0 Fossil Generation 2 1972 Gas 21.0 Fossil Generation - -------------------------------------------------------------------------------------------------------------------------------- Wolf Creek Generating Station (47%): Nuclear 1 (a) 1985 Uranium 550.0 Nuclear Generation - -------------------------------------------------------------------------------------------------------------------------------- Total 5,947.2 ======= - -------------------------------------------------------------------------------------------------------------------------------- - ---------------- (a) We jointly own Jeffrey Energy Center (84%), LaCygne 1 generating unit (50%), Wolf Creek Generating Station (47%) and State Line (40%). Unit capacity amounts reflect Western Resources' ownership only. (b) In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the LaCygne 2 generating unit. 25
We own approximately 6,700 miles of transmission lines, approximately 25,000 miles of overhead distribution lines and approximately 3,000 miles of underground distribution lines. (These properties are part of the Customer Operations segment.) Financing - --------- Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding. MONITORED SERVICES FACILITIES - ----------------------------- Protection One maintains its executive offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Protection One and Protection One Europe operate primarily from the following facilities, although Protection One also leases office space for approximately 60 service branch offices and seven satellite branches in North America and Protection One Europe leases offices for approximately 35 sales branch offices in continental Europe. - ------------------------------------------------------------------------------------------------------------------------------ Protection One: Size Location (Sq. ft.) Lease/Own Principal Purpose - ------------------------------------------------------------------------------------------------------------------------------ United States: Addison, TX (a)............ 28,512 Lease Monitoring facility/Multifamily administrative headquarters Irving, TX (a)............. 53,750 Lease Monitoring facility/administrative headquarters Orlando, FL................ 11,020 Lease Wholesale monitoring facility Portland, ME............... 9,000 Lease Monitoring facility/local branch Topeka, KS................. 17,703 Lease Financial/administrative headquarters Wichita, KS................ 50,000 Own Monitoring facility/administrative functions Canada: Ottawa, ON................. 7,937 Lease Monitoring facility/administrative headquarters Vancouver, BC.............. 5,177 Lease Monitoring facility - ------------------------------------------------------------------------------------------------------------------------------ Protection One Europe: Size Location (Sq. ft.) Lease/Own Principal Purpose - ------------------------------------------------------------------------------------------------------------------------------ Europe: Paris, France.............. 3,498 Lease Financial/Administrative offices/Monitoring facility Vitrolles, France.......... 27,000 Lease Administrative/Monitoring facility Dusseldorf, Germany........ 7,800 Lease Administrative/Warehouse Brussels, Belgium.......... 14,400 Lease Administrative/Warehouse - ------------------------------------------------------------------------------------------------------------------------------ - ---------- (a) In 2002, the administrative headquarters and monitoring operations for Protection One's Network Multifamily (Multifamily) segment will be relocated to the Irving, Texas facility. 26
ITEM 3. LEGAL PROCEEDINGS - ------------------------- The SEC commenced a private investigation in 1997 relating to, among other things, the timeliness and adequacy of disclosure filings with the SEC by us with respect to securities of ADT Ltd. We have cooperated with the SEC staff in this investigation. We, Westar Industries, Protection One, Protection One Alarm 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, "Alec Garbini, 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. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint (Third Amended Complaint). Plaintiffs purported to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and bonds, during the period of February 10, 1998 through February 2, 2001. The Third Amended Complaint asserted claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Protection One Alarm 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, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs alleged, 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 Third Amended Complaint further asserted claims against us and Westar Industries 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 was also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Third Amended Complaint sought an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. On June 4, 2001, the District Court dismissed plaintiffs' claims under Sections 10(b) and 20(a) of the Securities Exchange Act. The Court granted plaintiffs leave to replead such claims. The Court also dismissed all claims brought on behalf of bondholders with prejudice. The Court also dismissed plaintiffs' claims against Arthur Andersen and the plaintiffs have appealed that dismissal. On February 22, 2002, plaintiffs filed a Fourth Consolidated Amended Class Action Complaint. The new complaint realleges claims on behalf of purchasers of common stock 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. The defendants have until April 5, 2002 to respond to the new complaint. Protection One and we cannot predict the impact of this litigation, which could be material. We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provision has been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations. See also Notes 3 and 15 of the "Notes to Consolidated Financial Statements" for discussion of FERC proceedings and the lawsuit PNM filed against us and the KCC regulatory proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ----------------------------------------------------------- No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2001. 27
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS - ----------------------------------------------------------------------------- STOCK TRADING Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of March 14, 2002, there were 35,839 common shareholders of record. For information regarding quarterly common stock price ranges for 2001 and 2000, see Note 27 of the "Notes to Consolidated Financial Statements." DIVIDENDS Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, dividends must be first paid to the holders of preferred stock based on the fixed dividend rate for each series and our obligations with respect to mandatorily redeemable preferred securities issued by subsidiary trusts must be met. Quarterly dividends on common stock and preferred stock normally are paid on or about the first of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews its common stock dividend policy from time to time. Among the factors the board of directors considers in determining its dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. In March 2000, we announced a quarterly dividend of $0.30 per share (an indicated dividend rate of $1.20 per share on an annual basis). We expect to maintain the dividend at this level in 2002. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM. Our Articles of Incorporation contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate. For information regarding quarterly dividend declarations for 2001 and 2000, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." See also Note 18 of the "Notes to Consolidated Financial Statements" included herein. 28
ITEM 6. SELECTED FINANCIAL DATA - ------------------------------- For the Year Ended December 31, ------------------------------------------------------------------------ 2001 2000 1999(a) 1998(b) 1997(c) ---------- ---------- ---------- ---------- ---------- (In Thousands) Income Statement Data: Sales ............................................... $2,186,262 $2,368,476 $2,030,087 $2,034,054 $2,151,765 Net income (loss) before extraordinary gain and accounting change ................................ (62,726) 91,050 2,554 34,058 498,652 Earnings (loss) available for common stock ............................................ (21,771) 135,352 13,167 32,058 493,733 As of December 31, ------------------------------------------------------------------------ 2001 2000 1999(a) 1998(b) 1997(c) ---------- ---------- ---------- ---------- ---------- (In Thousands) Balance Sheet Data: Total assets ........................................ $7,513,065 $7,801,720 $7,989,892 $7,929,776 $6,945,350 Long-term debt, net, and other mandatorily redeemable securities ............................ 3,198,382 3,457,849 3,103,066 3,283,064 2,391,889 For the Year Ended December 31, ------------------------------------------------------------------------ 2001 2000 1999(a) 1998(b) 1997(c) ---------- ---------- ---------- ---------- ---------- Common Stock Data: Basic and diluted earnings (losses) per share available for common stock before extraordinary gain and accounting change ....................... $ (0.90) $ 1.30 $ 0.02 $ 0.46 $ 7.58 Basic and diluted earnings (losses) per share available for common stock ....................... $ (0.31) $ 1.96 $ 0.20 $ 0.48 $ 7.58 Dividends per share (d) ............................. $ 1.20 $ 1.44 $ 2.14 $ 2.14 $ 2.10 Book value per share ................................ $ 25.60 $ 27.20 $ 28.03 $ 29.21 $ 30.86 Average shares outstanding (000's) .................. 70,650 68,962 67,080 65,634 65,128 - ---------- (a) Information reflects the impairment of marketable securities and the change to an accelerated amortization method for the monitored services segment's customer accounts. (b) Information reflects exit costs associated with international power development activities. (c) Information reflects the gain on the sale of Tyco common shares, our strategic alliance with ONEOK and the acquisition of Protection One. (d) In March 2000, we announced a new dividend policy. See "Item 5. Market for Registrant's Common Equity and Related Stockholder Matters -- Dividends." 29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS - ------------------------------------------------------------------------------- OF OPERATIONS - ------------- INTRODUCTION In Management's Discussion and Analysis, we discuss the general financial condition, significant annual changes and the operating results for us and our subsidiaries. We explain: . what factors impact our business, . what our earnings and costs were in 2001, 2000 and 1999, . why these earnings and costs differ from year to year, . how our earnings and costs affect our overall financial condition, . what our capital expenditures were for 2001, . what we expect our capital expenditures to be for the years 2002 through 2004, . how we plan to pay for these future capital expenditures, . critical accounting policies, and . any other items that particularly affect our financial condition or earnings. As you read Management's Discussion and Analysis, please refer to our consolidated financial statements and the notes thereto, which show our operating results. SUMMARY OF SIGNIFICANT ITEMS PNM Transaction - --------------- On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters. On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the Kansas Corporation Commission (KCC) orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely. 30
KCC Rate Cases - -------------- On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a $41.2 million reduction in KGE's rates and an $18.5 million increase in our rates. On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court. KCC Proceedings and Orders - -------------------------- The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at the Federal Energy Regulatory Commission (FERC), seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the 31
proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect our results of operations. The Financial Plan - ------------------ The July 20, 2001 KCC order directed us to present a financial plan to the KCC. For details of the financial plan, see Note 15 of the "Notes to Consolidated Financial Statements." Extraordinary Gain on Extinguishment of Debt - -------------------------------------------- During the last three years, Protection One and our bonds were repurchased in the open market and extraordinary gains were recognized on the retirement of these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in 1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6 million, net of tax, was recognized on the repurchase of Protection One and our bonds. Impairment Charge Pursuant to New Accounting Rules - -------------------------------------------------- Effective January 1, 2002, we adopted the new accounting standards Statement of Financial Accounting Standard (SFAS) No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets." SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. SFAS No. 144 establishes a new approach to determining whether our customer account asset is impaired. The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of the goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream to be used under SFAS No. 144 is limited to the future estimated undiscounted cash flows of our existing customer accounts. Additionally, the new rule no longer permits us to include estimated cash flows from forecasted customer additions. If the undiscounted cash flow stream from existing customer accounts is less than the combined book value of customer accounts and goodwill, an impairment charge is required. The new rule substantially reduces the net undiscounted cash flows used for impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16-year remaining life of the goodwill to the nine-year remaining life of customer accounts for impairment evaluation purposes and does not include estimated cash flows from forecasted customer additions. 32
To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of goodwill and customer accounts. Based on this analysis, during the first quarter of 2002, we will record a non-cash net charge of approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. The charge is detailed as follows: Impairment of Impairment of Goodwill Customer Accounts Total ------------- ----------------- --------- (In Thousands) Protection One .............. $ 498,921 $ 334,064 $ 832,985 Protection One Europe ....... 80,104 -- 80,104 --------- --------- --------- Total pre-tax impairment .... $ 579,025 $ 334,064 913,089 ========= ========= Income tax benefit .......... (173,650) Minority interest ........... (85,713) --------- Net charge .................. $ 653,726 ========= The impairment charge for goodwill will be reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts will be reflected in our consolidated statement of income as an operating cost. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002. In 2001, we recorded approximately $57.1 million of goodwill amortization expense. We will no longer be permitted to amortize goodwill to income because of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0 million of customer account amortization expense. Future customer account amortization expense will also be reduced as a result of the impairment charge. We will be required to perform impairment tests for our monitored services segment for long-lived assets prospectively as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested each year for impairment. Declines in market values of our monitored services businesses or the value of customer accounts that may be incurred prospectively may require additional write down of these assets in the future. Estimated Lives of Customer Accounts to Change Based on Customer Account Lifing - ------------------------------------------------------------------------------- Study Results - ------------- Protection One is currently evaluating the estimated life and amortization rates for customer accounts, given the results of a lifing study performed by a third party appraisal firm in the first quarter of 2002. Any change in its amortization rate or estimated life will be determined in the first quarter of 2002 and accounted for prospectively as a change in estimate. Work Force Reductions - --------------------- In late 2001, we reduced our utility work force by approximately 200 employees through involuntary separations and recorded a severance-related net charge of approximately $14.3 million. In 2001, Protection One also reduced its work force by approximately 500 employees in connection with facility consolidations and recorded a severance-related net charge of approximately $3.1 million. In the first quarter of 2002, we further reduced our utility work force by approximately 400 employees through a voluntary separation program. We expect to record a net charge of approximately $21.1 million in the first quarter of 2002 related to this program. We may replace some of these employees. Protection One also reduced its work force by approximately 200 employees in connection with facility consolidations and expects to record a net severance charge of approximately $0.5 million in the first quarter of 2002. 33
Ice Storm - --------- In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. Marketable Securities - --------------------- During the fourth quarter of 1999, we decided to sell our remaining marketable security investments in paging industry companies. These securities were classified as available-for-sale; therefore, changes in market value were 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, a non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in the accompanying consolidated statements of income. During the first quarter of 2000, we sold the remainder of our portfolio of paging company securities. We realized a gain of $24.9 million on these sales. This gain was largely attributable to a general increase in the market value of paging companies triggered by an announcement made by one paging company in February 2000 that had a favorable impact on the market value of public paging company securities. During 2000, we sold our equity investment in a gas compression company and realized a pre-tax gain of $91.1 million. During 2001, we wrote down the cost basis of certain equity securities to their fair value. The fair value of these equity securities had declined below our cost basis, and we determined that the decline was other than temporary. The amount of the write down totaled $11.1 million, of which $9.6 million related to a cost method investment. The write down is included in other income (expense). CRITICAL ACCOUNTING POLICIES Our discussion and analysis of results of operations and financial condition are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (GAAP). The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, investments, customer accounts, goodwill, intangible assets, income taxes, pensions and other post-retirement benefits, and contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. Note 2 of the "Notes to Consolidated Financial Statements" includes a summary of the significant accounting policies and methods used in the preparation of our consolidated financial statements. The following is a brief description of the more significant accounting policies and methods used by us. Regulatory Accounting - --------------------- We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of 34
Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. As of December 31, 2001, this would reduce our earnings by $352.0 million, net of applicable income taxes. SFAS No. 71 applies to our fossil generation, nuclear generation, and customer operations business segments. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See "-- Other Information -- Electric Utility -- Competition and Deregulation" and "-- Other Information -- Electric Utility -- Stranded Costs" for additional discussion of the application of SFAS No. 71. Revenue Recognition - ------------------- Energy Sales: Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for power marketing. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets. We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense. Monitored Services Revenues: Monitored services revenues are recognized when security services are provided. Installation revenue, sales revenues on equipment upgrades and direct costs of installations and sales are deferred for residential customers with service contracts. For commercial customers and national account customers, revenue recognition is dependent upon each specific customer contract. In instances when the company sells the equipment outright, revenues and costs are recognized in the period incurred. In cases where there is no outright sale, revenues and direct costs are deferred and amortized. Deferred installation revenues and system sales revenues will be recognized over the expected useful life of the customer. Deferred costs in excess of deferred revenues will be recognized over the contract life. To the extent deferred costs are less than deferred revenues, such costs are recognized over the customers' estimated useful life. Deferred revenues also result from customers who are billed for monitoring, extended service protection and patrol and response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. 35
Depreciation - ------------ Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek, for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $17.6 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application. Non-utility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. We periodically evaluate our depreciation rates considering the past and expected future experience in the operation of our facilities. Depreciable lives of property, plant and equipment are as follows: Utility: Fossil generating facilities............................. 10 to 48 years Nuclear generating facilities............................ 38 years Transmission facilities.................................. 27 to 65 years Distribution facilities.................................. 14 to 65 years Other.................................................... 3 to 50 years Non-utility: Buildings................................................ 40 years Installed systems........................................ 10 years Furniture, fixtures and equipment........................ 5 to 10 years Leasehold improvements................................... 5 to 10 years Vehicles................................................. 5 years Data processing and telecommunications................... 1 to 7 years Valuation of Customer Account Intangible Assets - ----------------------------------------------- Customer accounts are stated at cost. Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One and Protection One Europe. These assets are tested for impairment in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," on a periodic basis or as circumstances warrant. For purposes of this impairment testing, goodwill is considered to be directly related to the acquired customer accounts. Factors we consider important that could trigger an impairment review include the following: . high levels of customer attrition; . continuing recurring Monitored Services losses; and . declines in the market value of Protection One's publicly traded equity and debt securities. 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 related goodwill. Protection One and Protection One Europe have performed impairment tests on their customer account assets and goodwill as of December 31, 2001. These tests have indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill. See "-- Summary of Significant Items -- Impairment Charge Pursuant to New Accounting Rules" for a discussion of the impairment recorded on these assets in the first quarter of 2002 pursuant to the adoption of new accounting rules. 36
Income Taxes - ------------ As part of the process of preparing our consolidated financial statements we are required to estimate our income taxes in each of the jurisdictions in which we operate. Significant management judgment is required in determining our provision for income taxes and our deferred tax assets and liabilities. This process involves us estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation and amortization, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheet. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income. To the extent we believe that recovery is not likely, we must establish a valuation allowance. At the current time, we believe our deferred tax assets will be recovered from future taxable income. In the event that actual results differ from these estimates, or we adjust these estimates in future periods, we may need to establish a valuation allowance that could materially impact our financial position and results of operations. Cumulative Effect of Accounting Change - -------------------------------------- Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in fossil fuel purchases and electricity sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value. Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle. After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under "-- Revenue Recognition -- Energy Sales." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings. OPERATING RESULTS Western Resources Consolidated - ------------------------------ 2001 compared to 2000: We reported losses per share of $0.31 in 2001 compared to earnings per share of $1.96 in 2000. This decrease resulted from decreased electricity sales caused by milder weather, the decrease in electric rates in accordance with the July 25, 2001 KCC rate order, higher operating losses at Protection One and Protection One Europe, and the fourth quarter charge related to a work force reduction. Additionally, investment earnings and the extraordinary gains on the retirement of debt were lower in 2001 than in 2000. 37
2000 compared to 1999: Earnings per share were $1.96 in 2000 compared to $0.20 in 1999. This increase is primarily attributable to increased earnings from the sale of investments and the extraordinary gain on the retirement of Protection One bonds. This increase was partially offset by a change in the estimated life of goodwill and operating losses from our monitored services segment. Business Segments - ----------------- Our business is segmented based on differences in products and services, production processes and management responsibility. Based on this approach, we have identified five reportable segments: Fossil Generation, Nuclear Generation, Customer Operations, Monitored Services and Other. The Fossil Generation, Nuclear Generation and Customer Operations segments comprise our electric utility business. Fossil Generation produces power for sale internally to the Customer Operations segment and externally to wholesale customers. A component of our Fossil Generation segment is power marketing, which attempts to minimize commodity price risk associated with fuel purchases and purchased power requirements. Power marketing also attempts to maximize utilization of generation capacity and enhance system reliability through sales to external customers as discussed further below. Nuclear Generation represents our 47% ownership in the Wolf Creek Generating Station (Wolf Creek). This segment has only internal sales because it provides all of its power to its co-owners. The Customer Operations segment consists of the transmission and distribution of power to our retail customers in Kansas and the customer service provided to these customers and the transmission of wholesale energy. Monitored Services is comprised of our security alarm monitoring business in North America and Europe. Other includes a 45% interest in ONEOK, investments in international power generation facilities and other investments, which in the aggregate are not material to our business or results of operations. We manage our business segments' performance based on their earnings before interest and taxes (EBIT). EBIT does not represent cash flow from operations as defined by GAAP, should not be construed as an alternative to operating income and is indicative neither of operating performance nor cash flows available to fund our cash needs. Items excluded from EBIT are significant components in understanding and assessing our financial performance. We believe presentation of EBIT enhances an understanding of financial condition, results of operations and cash flows because EBIT is used by us to satisfy our debt service obligations, capital expenditures and other operational needs, as well as to provide funds for growth. Our computation of EBIT may not be comparable to other similarly titled measures of other companies. Electric Utility: Our electric utility operations supply electric energy at retail to approximately 640,000 customers in Kansas. These customers are classified as residential, commercial and industrial as defined in our tariffs. Sales classifications and the related descriptions for our remaining electricity sales are as follows: . Wholesale and Interchange: Sales consist of electric energy supplied to the electric distribution systems of 63 Kansas cities and 4 rural electric cooperatives. It also includes contracts for the sale, purchase or exchange of electricity with other utilities and/or marketers. . Power Marketing: Sales made in areas outside of our historical marketing territory. These sales are non-asset based, which means that we do not use power produced by our generating facilities for these sales. . System Marketing: Financial transactions entered into on behalf of system requirements. . Other: Includes public street and highway lighting and miscellaneous electric revenues. Many things will affect our future electric sales. Our regulated electric utility sales are significantly impacted by such things as the weather, regulation (including rate regulation), customer conservation efforts, wholesale demand, the overall economy of our service area, the City of Wichita's attempt to create a municipal electric utility, and competitive forces. Our sales are impacted by demand outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity. 38
Our electric sales for the last three years ended December 31 are as follows: 2001 2000 1999 ---------- ---------- ---------- (In Thousands) Residential .......................... $ 419,492 $ 452,674 $ 407,371 Commercial ........................... 380,277 367,367 356,314 Industrial ........................... 244,392 252,243 251,391 Other ................................ 50,669 49,629 46,306 ---------- ---------- ---------- Total retail .................... $1,094,830 $1,121,913 $1,061,382 Wholesale and Interchange ............ 233,129 214,721 174,895 Power Marketing ...................... 408,242 457,178 190,101 System Marketing ..................... 32,192 35,321 3,320 ---------- ---------- ---------- Total ........................... $1,768,393 $1,829,133 $1,429,698 ========== ========== ========== The following tables reflect changes in electric sales volumes, as measured by megawatt hours (MWh), for the years ended December 31, 2001, 2000 and 1999. No amounts are included for power marketing and system marketing sales because these sales are not based on electricity we generate. 2001 2000 % Change ------ ------ -------- (Thousands of MWh) Residential ...................................... 5,755 6,222 (7.5) Commercial ....................................... 6,742 6,485 4.0 Industrial ....................................... 5,617 5,820 (3.5) Other ............................................ 107 108 (0.9) ------ ------ Total retail ................................ 18,221 18,635 (2.2) Wholesale and Interchange ........................ 7,547 6,892 9.5 ------ ------ Total ....................................... 25,768 25,527 0.9 ====== ====== 2000 1999 % Change ------ ------ -------- (Thousands of MWh) Residential ...................................... 6,222 5,551 12.1 Commercial ....................................... 6,485 6,202 4.6 Industrial ....................................... 5,820 5,743 1.3 Other ............................................ 108 108 -- ------ ------ Total retail ................................ 18,635 17,604 5.9 Wholesale and Interchange ........................ 6,892 5,617 22.7 ------ ------ Total ....................................... 25,527 23,221 9.9 ====== ====== 2001 compared to 2000: Energy sales decreased $60.7 million, or 3%. --------------------- Residential sales declined 7% and power marketing sales declined 11%. Residential sales decreased due to weather conditions and our rate decrease, while power marketing sales decreased because of lower prices and more power available in the market. Cost of sales increased $5.3 million, or 1%, over 2000. As a result gross profit decreased $66.0 million, or 7%. This decline in gross profit is partly due to how we were required to record a gain on certain fuel derivatives acquired in 2000 to mitigate the risk of changing prices on our natural gas fuel requirements. Prior to the adoption of SFAS No. 133 on January 1, 2001, gains and losses on these fuel derivatives were deferred until settlement and reflected in gross profit at that time. However, upon adoption of SFAS No. 133, we were required to report our $31.0 million gain on these contracts as of that date as a cumulative effect of a change in accounting principle. This gain is reported on our consolidated statements of income on a net-of-tax basis below income tax expense. We are not permitted to reflect the cumulative effect of an accounting change in gross profit. As a result, the benefit of our efforts in 2000 to mitigate the risk of price changes on our 2001 fuel requirements is not reflected in gross profit. 39
Had we been permitted to classify this as a reduction to cost of sales, our $66.0 million decline in gross profit would have been reduced by $31.0 million. All gains and losses after January 1, 2001 on our fuel derivatives that are not designated as hedges are reflected in gross profit. 2000 compared to 1999: Electric operations gross profit increased $28.3 --------------------- million, or 3%. The increase is due primarily to increased power marketing sales. Electric operations gross profit as a percentage of sales decreased to 54% from 67% primarily due to higher fuel and purchased power prices. (See "-- Other Information -- Market Risk Disclosure" for further discussion.) Additionally, we experienced a 12% increase in residential sales volumes and a 23% increase in wholesale and interchange sales volumes. The increase in residential sales was primarily due to increased demand caused by warm weather. Cooling-degree days increased by 27%. The increase in wholesale and interchange sales volumes was primarily due to increased wholesale market opportunities. Items included in energy cost of sales are fuel expense, purchased power expense (electricity we purchase from others for resale) and power marketing expense. Partially offsetting the higher sales was an increase of $371.2 million in cost of sales primarily due to higher power marketing expense of $263.0 million and increased fuel and purchased power expenses of approximately $75.1 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale and interchange sales volumes. Fossil Generation: ----------------- Fossil Generation's external sales consist of the power produced and purchased for sale to wholesale customers and includes power marketing sales, system marketing sales and wholesale and interchange sales. Internal sales consist of the power produced for sale to Customer Operations. Details concerning our earnings before interest and taxes attributable to fossil generation are as follows. For the years ended December 31, -------------------------------- 2001 2000 1999 -------- -------- -------- (In Thousands) Fossil Generation: External sales ........................ $667,953 $705,536 $365,311 Internal sales (a) .................... 560,528 572,533 546,683 Depreciation and amortization ......... 65,875 60,331 55,320 EBIT (b) .............................. 120,530 202,744 219,087 - ---------- (a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy. (b) EBIT for 2001 does not include the unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle as explained above. If the effect had been included, EBIT for the Fossil Generation segment for the year ended December 31, 2001 would have been $151.6 million. 2001 compared to 2000: External sales decreased $37.6 million primarily ---------------- due to a decrease in power marketing sales of $48.9 million, or 11%, and a decrease in system marketing sales of $3.1 million, or 9%. These decreases were partially offset by an increase in wholesale and interchange sales of $18.4 million, or 9%. The decrease in power marketing sales was primarily due to lower market demand and prices. EBIT decreased $82.2 million primarily due to decreased sales, a $30.8 million non-cash mark-to-market adjustment on fuel derivatives and increased fuel and purchased power expenses. Had SFAS No. 133 permitted us to include the cumulative gain effect in gross profit, EBIT would have decreased $51.2 million. 2000 compared to 1999: External sales increased $340.2 million primarily --------------------- due to power marketing sales, which increased by $267.1 million, wholesale and interchange sales, which increased by $39.8 million, and system 40
marketing sales, which increased by $32.0 million. Since 1997, we have gradually increased the size of our power trading operation in an effort to better utilize our market knowledge and to mitigate the risk associated with energy prices. While sales increased significantly, EBIT was $16.3 million lower because of higher cost of sales. Cost of sales was $371.2 million higher primarily due to higher power marketing expense of $263.0 million, increased fuel and purchased power expenses of approximately $71.6 million and system marketing transaction costs of approximately $33.1 million. Fuel and purchased power expenses were higher primarily due to increased commodity prices, increased demand from retail customers because of warmer weather and higher wholesale and interchange sales volumes. The cost of fuel in 2000 was significantly affected by increased gas costs of $13.3 million (despite a 9% reduction in MMBtu of gas burned). Our average natural gas price increased 45% during the year compared to 1999. Additionally, coal costs increased by $35.1 million, primarily due to increasing the quantities of coal burned in our efforts to minimize gas costs, and cost of oil increased $7.2 million, primarily due to increased price and increasing the quantities of oil burned. See "-- Other Information -- Market Risk Disclosure" for further discussion. Nuclear Generation: ------------------ Nuclear Generation has only internal sales because all of its power is provided to its co-owners: KGE, Kansas City Power and Light Company (KCPL) and Kansas Electric Power Cooperative, Inc. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek. Details concerning our earnings before interest and taxes attributable to our nuclear generation are as follows: For the years ended December 31, ------------------------------------- 2001 2000 1999 --------- --------- --------- (In Thousands) Nuclear Generation: Internal sales (a) ........................ $ 117,659 $ 107,770 $ 108,445 Depreciation and amortization ............. 41,046 40,052 39,629 Earnings (losses) before interest and taxes ............................... (19,078) (24,323) (25,214) - ---------- (a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy. Wolf Creek operated the entire year of 2001 without any refueling outages. Wolf Creek shut down for 38 days beginning on September 29, 2000 for its eleventh scheduled refueling and maintenance outage. Internal sales and EBIT increased during 2001 since the unit operated more during 2001 than during 2000. During 1999, there was a 36-day refueling and maintenance outage at Wolf Creek. Since both 2000 and 1999 had refueling outages, the change in internal sales and EBIT between 2000 and 1999 was immaterial. Wolf Creek has a scheduled refueling and maintenance outage approximately every 18 months. An outage began on March 23, 2002. During an outage, Wolf Creek produces no power for its co-owners; therefore internal sales, EBIT and nuclear fuel expense decrease. Customer Operations: ------------------- Customer Operations' external sales consist of the transmission and distribution of power to our electric retail and wholesale customers. Internal sales consist of the intra-segment transfer price charged to Fossil Generation and Nuclear Generation for the use of the distribution lines and transformers. 41
For the years ended December 31, -------------------------------------- 2001 2000 1999 ---------- ---------- ---------- (In Thousands) Customer Operations: External sales .................. $1,100,443 $1,123,590 $1,064,385 Internal sales (a) .............. 317,056 291,927 293,522 Depreciation and amortization ... 78,235 75,419 71,717 EBIT ............................ 131,917 171,872 145,603 - ---------- (a) When sales are made between the segments, the internal transfer price is determined by us using internally developed transfer pricing estimates that, while not based on market rates, represent what we believe would be market prices for capacity and energy. 2001 compared to 2000: External sales decreased $23.1 million, or 2%, and --------------------- EBIT decreased $40.0 million, or 23%, as a result of less favorable weather conditions and rate reductions ordered by the KCC. Weather conditions resulted in an approximate 8% decrease in residential sales volumes. In our service territory, the heating season of 2001 was warmer than the heating season of 2000, which caused customers to use less energy heating their homes during the winter. Additionally, the cooling season of 2001 was cooler than in 2000, which caused customers to use less energy to cool their homes during the summer. 2000 compared to 1999: External sales increased $59.2 million, or 6% and --------------------- EBIT increased $26.3 million, or 18%. We experienced a 12% increase in residential sales volumes primarily due to a 27% increase in cooling-degree days and a 15% increase in heating-degree days, which increased the demand for power on our system. Monitored Services: Protection One and Protection One Europe comprise our monitored services business segment. The results discussed below reflect Monitored Services on a stand-alone basis. These results do not take into consideration Protection One's minority interest of approximately 13% at December 31, 2001 and 15% at December 31, 2000 and 1999. Details concerning our earnings before interest and taxes attributable to our monitored services segment are as follows: For the years ended December 31, ------------------------------------- 2001 2000 1999 --------- --------- --------- (In Thousands) External sales ............................... $ 416,509 $ 537,859 $ 599,105 Depreciation and amortization ................ 228,123 248,414 233,906 Earnings (losses) before interest and taxes .. (126,076) (91,370) (20,675) 2001 compared to 2000: Sales decreased $121.4 million primarily due to a --------------------- decline in Monitored Services' average customer base and the disposition of certain operations. Monitored Services experienced a net decline of 267,347 customers in 2001. This decrease in customers is primarily attributable to customer attrition and a decrease of 63,875 customers due to the disposition of operations. Additionally, the number of Protection One customers declined by 62,443 customers due to the conversion of accounts to a common billing and monitoring system. This new system reports number of customer accounts on the basis of one customer for every location provided service even if Protection One has separate contracts to provide multiple services at that location. Previous systems utilized a number of different billing and monitoring software programs, some of which would count each separate contracted service as a separate account regardless of the location. Protection One's customer acquisition strategies have not been able to generate accounts in a sufficient volume at an acceptable cost to replace accounts lost through attrition. See "-- Other Information -- Monitored Services -- Attrition" below for discussion regarding attrition. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce attrition become more successful than they have been to date. Until it is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. In 42
2001, Protection One focused on the completion of its infrastructure projects, cost reductions, the development of cost effective marketing programs and the generation of positive cash flow. Loss before interest and taxes increased $34.7 million due primarily to the decrease in sales. Cost of sales decreased $41.6 million primarily due to the discontinuation of Protection One's Patrol services in May 2001, consolidation of Protection One customer monitoring facilities, a reduction of Protection One's telecommunications expense, consolidation of monitoring and customer service functions and the decline in customer accounts caused by dispositions of operations and attrition. See "-- Other Information -- Monitored Services -- Attrition" below for additional information. 2000 compared to 1999: Sales decreased $61.0 million primarily due to a --------------------- decline in customer base and the effect of the adoption of Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition." Adoption of SAB No. 101 reduced revenue by $10.9 million. In North America, Protection One had a net decrease of 141,527 customers in 2000 as compared to a net increase of 8,595 customers in 1999. The decrease in customers is primarily attributable to the fact that Protection One's present customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace accounts lost through attrition. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce attrition become more successful than they have been to date. Until Protection One is able to reverse this trend, net losses of customer accounts will materially and adversely affect its business, financial condition and results of operations. In 2000, Protection One focused on the completion of its infrastructure projects, the development of cost effective marketing programs, the development of its commercial business and the generation of positive cash flow. Protection One Europe had a net increase of 9,115 customers. The increase was primarily due to internal marketing efforts. Losses before interest and taxes increased $70.7 million due to lower sales, higher cost of sales and lower other income. Cost of sales increased $5.7 million due to increased compensation costs for additional personnel hired at Protection One's monitoring centers, an increase in the cost of parts and materials, and increased vehicle costs. Other income decreased because Protection One recorded a $17.2 million gain on the sale of the Mobile Services Group in the third quarter of 1999. Depreciation and amortization expense increased by $14.5 million primarily due to the change in the estimated life of goodwill which was reduced from 40 years to 20 years. Operating and maintenance expense decreased $13.6 million primarily due to declines in third party monitoring costs, signs and decals, printing and compensation expenses. These decreases are a direct result of the significant decline in the number of new accounts acquired during 2000 primarily due to the restructuring of Protection One's dealer program. WESTERN RESOURCES CONSOLIDATED The following discussion addresses changes in other items affecting net income but not affecting gross profit. Where a specific distinction based on segment cannot be determined for the items below, an allocation percent is used to determine the amounts to be applied to the segments for the calculation of EBIT. Since actual amounts for these items are not maintained by segment, they are discussed below in relation to the company as a whole, rather than as they may relate to specific reporting segments. Operating Expenses - ------------------ 2001 compared to 2000: In 2001, operating expenses increased $12.7 million primarily as a result of approximately $8.7 million of costs associated with the PNM transaction, approximately $28.5 million in employee-severance costs related to the work force reductions, and approximately $13.1 million associated with the dispositions of monitored services operations. Partially offsetting these increased costs were decreases in Monitored Services' depreciation and amortization expense of $20.3 million and reduced acquisition expenses of $7.8 million. The decline in depreciation 43
and amortization expense is primarily due to the accelerated depreciation of the billing and general ledger system Protection One used in 2000 and the change in the method of amortization utilized. The reduction in acquisition expense is primarily due to the reduced level of account acquisitions in 2001 as compared to 2000. 2000 compared to 1999: Operating expenses increased $13.7 million primarily due to increased depreciation and amortization expense of $22.7 million, of which $14.5 million relates to Monitored Services operations. Offsetting this increase is a $17.6 million charge in 1999 for deferred KCPL merger costs related to termination of the KCPL merger. Selling, general and administrative expenses were also higher due to a reduction of $5.6 million in 1999 related to international power development costs. Other Income (Expense) - ---------------------- 2001 compared to 2000: Other income was $57.6 million in 2001 compared to $201.0 million in 2000. Other income in 2001 includes $41.8 million of ONEOK investment income, a $5.3 million pre-tax gain related to the sale of Paradigm Direct LLC (Paradigm) and $7.6 million of interest income. These earnings were partially offset by impairment charges of $11.1 million recorded for declines in the value of marketable securities and other investments that were considered other than temporary in nature. The other income in 2000 includes $45.3 million of ONEOK investment income, a $91.1 million pre-tax gain on the sale of our investment in a gas compression company, a $24.9 million pre-tax gain on the sale of investments in paging companies, $7.8 million in equity earnings on investments and $9.8 million of interest income. 2000 compared to 1999: Other income increased $214.4 million primarily due to gains recorded in 2000 of $91.1 million on the sale of our remaining investment in a gas compression company and $24.5 million on the sale of marketable securities. During 1999, a special charge of $76.2 million was recorded related to our paging securities portfolio and a gain of $17.2 million was recorded on the sale of Protection One's Mobile Services Group. Interest Expense - ---------------- 2001 compared to 2000: Interest expense decreased $21.3 million due to lower interest rates and lower outstanding debt at Protection One. The weighted average interest rate on our revolving credit facility declined to 3.44% at December 31, 2001 from 8.11% at December 31, 2000. 2000 compared to 1999: We retired long-term debt during 2000 and 1999, causing long-term debt interest expense to decrease by $10.0 million for the year ended December 31, 2000. The retirements included Western Resources' first mortgage bonds of $125 million in 1999 and $75 million in 2000. In the fourth quarter of 1999 and during 2000, Protection One retired bonds with an aggregate face value of $237.9 million. For more information, see "-- Liquidity and Capital Resources" below. Short-term debt interest expense was $5.5 million higher due to increased short-term borrowings under our credit facilities. The majority of this short-term debt was repaid in the third quarter of 2000 with proceeds from the $600 million term loan. 44
Income Taxes - ------------ 2001 compared to 2000: Income taxes decreased $126.9 million in 2001 compared to 2000. This was primarily due to the decreased earnings before income taxes in 2001 resulting from the factors discussed previously. Our overall effective tax rate changed from a 33.6% expense in 2000 to a 56.3% benefit in 2001. The change in our effective tax rate was primarily due to decreased earnings before income taxes in 2001. The tax benefit from decreased earnings combined with our net tax benefits from dividends received, low income housing tax credits, the amortization of prior years' investment tax credits, the amortization of non-deductible goodwill, and the tax benefits from corporate-owned life insurance created this change in the effective tax rate. 2000 compared to 1999: Income taxes increased $78.3 million in 2000 compared to 1999. This was primarily due to the increased earnings before income taxes in 2000 resulting from the factors discussed previously. Our overall effective tax rate increased from a 108.6% benefit in 1999 to a 33.6% expense in 2000. The increase in our effective tax rate was primarily due to increased earnings before income taxes in 2000. This increase in earnings before income taxes reduces the impact of our net tax benefits (as mentioned previously) on the effective tax rate. 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, 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 from operations and the issuance of stock or long- 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 $96.7 million in cash and cash equivalents at December 31, 2001. We consider cash equivalents to be highly liquid investments with a maturity of three months or less when purchased. We also had $14.8 million of restricted cash classified as a current asset. The current asset portion of our restricted cash consists primarily of cash held in escrow as required by certain letters of credit. In addition, we had $38.5 million of restricted cash classified as a long-term asset. The long-term restricted cash consists primarily of $34.1 million cash held in escrow as required by the terms of a pre-paid capacity and transmission agreement and $4.4 million cash used to collateralize letters of credit and cash held in escrow. At December 31, 2001, current maturities of long-term debt increased $118.8 million from 2000 primarily because $100 million of our first mortgage bonds due August 15, 2002 were moved to current maturities. On June 28, 2000, we entered into a $600 million, multi-year term loan that replaced two revolving credit facilities that matured on June 30, 2000. We had $591 million outstanding on the term loan at December 31, 2001. The term loan is secured by our and KGE's first mortgage bonds and has a maturity date of March 17, 2003. The term loan agreement contains requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. At December 31, 2001, we were in compliance with all of these requirements. In January 2002, we repaid $44 million of the term loan with the proceeds of our sale of investments in low income housing tax credit partnerships. The outstanding balance of the term loan after this prepayment was $547 million. In March 2002, we entered into an amendment to the term loan that adds to the calculation of consolidated earnings before interest, taxes, depreciation and amortization, the severance costs incurred in the fourth quarter of 2001 and the first quarter of 2002 related to our work force reductions, and maintains the current maximum consolidated leverage ratio of 5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect to be in compliance with all covenants through the remaining term of this agreement. 45
Maturities of the term loan through March 17, 2003 are as follows: Principal Amount Year (In Thousands) ---- -------------- 2002 $ 6,000 2003 541,000 ------------ $ 547,000 ============ Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. For the year ended December 31, 2001, the weighted average interest rate on the term loan, including amortization of fees and interest swaps was 7.9%. Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge. We also have an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and KGE's first mortgage bonds and matures on March 17, 2003. Borrowings on this facility were $222.3 million at December 31, 2001 and $366.0 million at March 21, 2002. Under the terms of the agreement, we are required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. We are in compliance with this covenant. At December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the facility, the impairment charge to be recorded in the first quarter of 2002 will not affect compliance with this covenant in future periods. We have registered securities for sale with the Securities and Exchange Commission (SEC). As of December 31, 2001, these included $400 million of unsecured senior notes, $500 million of our first mortgage bonds, $50 million of KGE first mortgage bonds and approximately 11.2 million of our common shares. Our ability to issue additional debt and equity securities is restricted under limitations imposed by the Articles of Incorporation 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 (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on, or 10% of the principal amount of, all first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2001, no additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with refundings. 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 less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. In addition, the issuance of bonds is subject to limitations based upon the amount of bondable property additions. As of December 31, 2001, approximately $279 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage. 46
The table below shows the projected future cash payments for our contractual obligations existing at December 31, 2001: Payments Due by Period At December 31, 2001: --------------------------------------------------- Contractual Obligations Total 2002 2003 - 2004 2005 - 2006 Thereafter ---------- ---------- ----------- ----------- ---------- (Dollars in Thousands) Long-term debt ........................... $3,138,958 $ 160,576 $ 1,079,542 $ 406,871 $1,491,969 Operating leases ......................... 830,771 69,897 125,264 119,292 516,318 Fossil fuel .............................. 2,099,778 229,675 323,945 213,718 1,332,440 Nuclear fuel ............................. 84,038 -- 27,449 10,389 46,200 Unconditional purchase obligations (a) ... 10,150 4,060 6,090 -- -- ---------- ---------- ----------- ----------- ---------- Total contractual obligations ...... $6,163,695 $ 464,208 $ 1,562,290 $ 750,270 $3,386,927 ========== ========== =========== =========== ========== - ---------- (a) Represents Protection One's contract tariff for telecommunication services. The table below shows our total commercial commitments and the expected expiration per period: At December 31, 2001: Amount of Commitment Expiration Per Period Total Amounts --------------------------------------------------- Other Commercial Commitments Committed 2002 2003 - 2004 2005 - 2006 Thereafter ------------- ---------- ----------- ----------- ---------- (Dollars in Thousands) Lines of credit .......................... $ 507,000 $ 7,000 $ 500,000 $ -- $ -- Standby letters of credit ................ 12,687 9,937 -- -- 2,750 ----------- ---------- ----------- ----------- ---------- Total commercial commitments ....... $ 519,687 $ 16,937 $ 500,000 $ -- $ 2,750 =========== ========== =========== =========== ========== Credit Ratings - -------------- Standard & Poor's Ratings Group (S&P), Fitch Investors Service (Fitch) and Moody's Investors Service (Moody's) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies' assessment of our ability to pay interest and principal on these securities. On June 1, 2001, Moody's placed our ratings under review with direction uncertain. On October 19, 2001, S&P removed us from its CreditWatch listing and changed our and KGE's ratings outlook to "negative." On November 7, 2001, S&P reaffirmed its negative outlook for us. As of March 14, 2002, ratings with these agencies are as follows: Western Resources Western KGE Protection One Protection One Mortgage Resources Mortgage Senior Senior Bond Unsecured Bond Unsecured Subordinated Rating Debt Rating Debt Unsecured Debt --------- --------- -------- -------------- -------------- S&P................ BBB- BB- BB+ B CCC+ Fitch.............. BB+ BB BB+ B CCC+ Moody's............ Ba1 Ba2 Ba1 B3 Caa2 In general, declines in our credit ratings make debt financing more costly and more difficult to obtain on terms which are economically favorable to us. Credit rating agencies are applying more stringent guidelines when rating utility companies due to increasing competition and utility investment in non-utility businesses. We do not have any credit rating conditions in any of the agreements under which our debt has been issued. Sale of Accounts Receivable - --------------------------- On July 28, 2000, we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a 47
special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001, and is annually renewable upon agreement by all parties. Under the terms of the agreement, we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. We service the receivables transferred to the SPE and receive a servicing fee. These servicing fees are eliminated in consolidation. Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest. We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income. The outstanding balance of SPE receivables was $43.3 million at December 31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided interest of $100.0 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets. Cash Flows from (used in) Operating Activities - ---------------------------------------------- Our primary sources of operating cash flows are the operations of our electric utility and monitored services businesses and dividends from our ONEOK investment. Cash flows from operating activities decreased $187.0 million to $224.8 million in 2001, from $411.8 million in 2000. This decrease is mostly attributable to changes in our working capital. Operating cash flows in 2001 also decreased due to the continued decline in Protection One's and Protection One Europe's customer base, which reduces our recurring monthly cash flow stream. Operating cash flows also decreased in 2001 as we purchased additional coal to restock our inventory from the levels that existed in December 2000. Cash flows from operating activities increased $43.3 million to $411.8 million in 2000, from $368.4 million in 1999. This increase is mostly attributable to the initial sale of accounts receivable in June 2000 offset by a decrease in utility gross margin percentage for 2000 compared to 1999. The decrease in gross margin percentage negatively affected operating cash flows as our cost of sales for the utility increased at a greater rate than sales in 2000 due to increasing fuel prices and an increase in the use of purchased power. Cash Flows from (used in) Investing Activities - ---------------------------------------------- In general, cash used for investing purposes relates to the growth and maintenance of the operations of our utility and monitored services businesses. The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $227.0 million in 2001 and $285.4 in 2000 on net additions to utility property, plant and equipment, including $52.2 million in 2001 and $87.7 million in 2000 on new generation projects. This was in addition to our normal maintenance requirements. The monitored services business also requires significant capital investment related to the acquisition of customer accounts. Investment in customer accounts in 2001 and 2000 amounted to $36.5 million and $47.3 million, respectively. Investing cash flows were also impacted significantly by the sale of marketable security investments and the 48
dispositions of non-strategic monitored services businesses. These activities produced cash of $50.8 million and $218.6 million in 2001 and 2000, respectively. We do not expect these to be sources of significant cash in 2002. Investing activities in 1999 required significantly more cash than in 2000 because Protection One invested $268.4 million in the purchase of customer accounts and security alarm businesses. Cash Flows from (used in) Financing Activities - ---------------------------------------------- We had a net cash flows from financing activities of $24.5 million in 2001 compared to net cash flows used in financing activities of $328.0 million in 2000. In 2001, an increase in short-term debt was the principal source of cash flows from financing activities. Cash from financing activities was used to fund our required investment in operations, the retirement of Protection One's long-term debt, and the payment of dividends on our common stock. In 2000, we reduced our annual dividend from $2.14 to $1.20 per share. This reduction, and continued reinvestment of dividends by our shareholders through the dividend reinvestment program, resulted in a significant reduction in our net cash dividend requirements. 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 at least the year 2004. Uncertainties affecting our ability to meet these requirements include the factors affecting sales described above, the impact of inflation on operating expenses, regulatory actions, the impact of the rate reduction, our ability to consummate the financial plan furnished to the KCC and to refinance our outstanding debt discussed under "-- Summary of Significant Items -- KCC Proceedings and Orders" above, compliance with future environmental regulations, municipalization efforts by the City of Wichita and the impact of our monitored services' 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 have $160.6 million of long-term debt that will mature in 2002 and $715.4 million of long-term debt and a $500 million revolving credit facility that will mature in 2003. Additionally, we have $384.3 million of putable/callable bonds that may either mature in August 2003 or be remarketed and repriced at current rates and which will mature in 2018. We believe we will be successful in refinancing these obligations but can give no assurance that these financings will be completed at similar costs to maturing debt. We forecast that we will need additional generating capacity of approximately 150 MW by 2006 to serve our customer's expected electricity needs. We will determine how to meet this need at a future date. Our business requires significant capital investments. We currently expect that through the year 2004, we will need cash mostly for: . Ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. . Improving operations within the monitored services business and the acquisition of customer accounts. Capital expenditures for 2001 and anticipated capital expenditures for 2002 through 2004 are as follows: Fossil Nuclear Customer Monitored Generation Generation Operations Services Total ---------- ---------- ---------- -------- -------- (In Thousands) 2001 ........... $116,595 $ 27,349 $ 83,052 $ 45,944 $272,940 2002 ........... 58,000 10,000 86,800 41,100 195,900 2003 ........... 70,100 30,100 86,800 43,800 230,800 2004 ........... 69,400 30,100 86,800 47,500 233,800 49
These estimates are prepared for planning purposes and will be revised from time to time. See Note 2 of the "Notes to Consolidated Financial Statements." Actual expenditures will differ from our estimates. Maturities of long-term debt as of December 31, 2001 are as follows: Principal Amount Year ---------- ---- (In Thousands) 2002 (a) .................. $ 160,576 2003 ...................... 715,414 2004 ...................... 364,128 2005 ...................... 306,414 2006 ...................... 100,457 Thereafter ................ 1,491,969 ---------- $3,138,958 ========== - ---------- (a) Amount due includes $38.5 million related to the sale of investments required to be repaid under the mandatory prepayment provisions of our credit agreement. Capital Structure - ----------------- Our capital structure at December 31, 2001 and 2000 was as follows: Pro forma 2001 2000 2001 (a) ---- ---- --------- Shareholders' equity ........................................... 36% 35% 26% 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, net ............................................ 59 60 68 --- --- --- Total .................................................... 100% 100% 100% === === === - ---------- (a) Subsequent to December 31, 2001, we recorded an impairment of our goodwill and customer accounts as more fully described in "-- Summary of Significant Items -- Impairment Charge Pursuant to New Accounting Rules." Had that charge occurred prior to year-end, our 2001 capital structure would have been as shown above in the "Pro forma 2001" column. Dividend Policy - --------------- Our board of directors reviews our dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, competition and financial loan covenants. Provisions in our Articles of Incorporation contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate. Our agreement with PNM prohibits an increase in the dividend paid on our common stock without the consent of PNM. Debt and Equity Repurchase Plans - -------------------------------- Westar Industries and Protection One may, from time to time, purchase Protection One's debt and equity securities in the open market or through negotiated transactions. We, Westar Industries and Protection One may also 50
purchase our debt and equity. The timing and terms of purchases and the amount of debt or equity actually purchased will be determined based on market conditions and other factors. OTHER INFORMATION Electric Utility - ---------------- City of Wichita Municipalization Effort: In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita, metropolitan area account for approximately 23% of our total energy sales. FERC Proceedings: On September 12, 2001, we filed a settlement between the FERC staff and Westar Generating, Inc. (Westar Generating), the wholly owned subsidiary that owns our interests in the State Line generating facility. The settlement establishes the rate at which we will buy power from Westar Generating. FERC has jurisdiction over the establishment of this rate because of our affiliate relationship with Westar Generating. We continue to work toward a global settlement with the KCC, the only other active party, but can make no assurance on a resolution. In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between our KPL division and KGE. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. We anticipate no further activity regarding this complaint because the City of Wichita's time to appeal FERC's order has expired. Competition and Deregulation: Electric utilities have historically operated in a rate-regulated environment. Federal and state regulatory agencies having jurisdiction over our rates and services and other utilities have initiated steps that were expected to result in a more competitive environment for utility services. The Kansas Legislature took no action on deregulation in 2001 or 2000. In a deregulated environment, utility companies that are not responsive to a competitive energy marketplace may suffer erosion in market share, revenues and profits. Possible types of competition include cogeneration, self-generation, retail wheeling, or municipalization. Retail wheeling is the ability of individual customers to choose a 51
power provider other than us and we would provide the transmission service for this power. Kansas does not allow retail wheeling and no such regulation is pending or being considered. However, if retail wheeling were implemented in Kansas, increased competition for retail electricity sales may reduce our future electric utility earnings compared to our historical electric utility earnings. Our rates range from approximately 10% to 20% below the national average for retail customers. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment. Increased competition for retail electricity sales may in the future reduce our earnings, which could impact our ability to pay dividends and could have a material adverse impact on our operations and our financial condition. A material non-cash charge to earnings may be required should we discontinue accounting under SFAS No. 71. See "-- Stranded Costs" below for additional information regarding SFAS No. 71. The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties the use of their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions thereby facilitating open and more competitive markets in bulk power. After the FERC rejected several attempts by the Southwest Power Pool (SPP) to seek RTO status, the SPP and the Midwest Independent System Operator (MISO) agreed in October 2001 to consolidate and form an RTO. In December 2001, the FERC approved this newly formed MISO as the first RTO. The agreement to consolidate was executed in February 2002 and the transaction is expected to close in 2003. This new organization will operate our transmission system as part of an interconnected transmission system encompassing over 120,000 MW of generation capacity located in 20 states. MISO will collect revenues attributable to the use of each member's transmission system, and each member will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire MISO system. Although each member will have priority over the use of its own transmission facilities for selling power to its wholesale customers or others, each member will be charged the same uniform transmission rate as other energy suppliers who are able to sell power to them. We intend to file with the FERC and the KCC to transfer control over the operation of our transmission facilities to MISO. We anticipate that FERC Order No. 2000 and our participation in the MISO will not have a material effect on our operations. Stranded Costs: The definition of stranded costs for a utility business is the investment in and carrying costs on property, plant and equipment and other regulatory assets that exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our fossil generation, nuclear generation and customer operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material extraordinary non-cash charge to earnings. Reasons for discontinuing SFAS No. 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred, a significant change by regulators from a cost-based rate regulation to another form of rate regulation and the impact should the City of Wichita municipalization efforts be successful. We periodically review SFAS No. 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based upon competitive or other events, such as the successful municipalization efforts by areas we serve, the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek, may be significantly impacted. Regulatory changes, including competition or successful municipalization efforts by the City of Wichita, could adversely impact our ability to recover our investment in these assets. As of December 31, 2001, we have recorded regulatory assets that are currently subject to recovery in future rates of approximately $358.0 million. Of this amount, $221.4 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs, including debt issuance costs, deferred employee benefit costs, deferred plant costs, and coal contract settlement costs. 52
In a competitive environment or because of such successful municipalization efforts, we may not be able to fully recover our entire investment in Wolf Creek. KGE presently owns 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net 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 shutdown 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 plants to prepare formal financial plans to fund decommissioning. These plans are designed so that funds required for decommissioning will be accumulated during the estimated remaining life of the related nuclear power plant. We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs for labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000. Decommissioning costs are currently being charged to operating expense in accordance with prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%. Our investment in the decommissioning fund, including reinvested earnings, approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. Asset Retirement Obligations: In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset. The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time. We do not believe that such changes, if required, 53
would adversely affect our operating results due to our current ability to recover decommissioning costs through rates. Monitored Services - ------------------ Attrition: Customer attrition has a direct impact on the results of our monitored security operations since it affects its revenues, amortization expense and cash flow. In some instances, estimates are used to derive attrition data. Adjustments are made to lost accounts primarily for the net change, either positive or negative, in the wholesale base and for accounts which are covered under a purchase price holdback and are "put" back to the seller. The gross accounts lost during a period are reduced by the amount of the guarantee provided for in the purchase agreements with sellers. In some cases, the amount of the purchase holdback may be less than actual attrition experience. The gross accounts lost during a period are not reduced by "move in" accounts, which are accounts where a new customer moves into a home installed with a Protection One security system and vacated by a prior customer, or "competitive takeover" accounts, which are accounts where the owner of a residence monitored by a competitor requests that we provide monitoring services. The decreases due to the conversions to MAS(R) were excluded in the calculation of attrition for the periods indicated below. For the year ended December 31, 2001, gross accounts lost were further reduced by 126,318 customers for account dispositions and for adjustments resulting from the conversion of Protection One's Wichita, Hagerstown, Beaverton and Irving billing and monitoring systems to a new technology platform, MAS(R). The conversion adjustments relate to how a customer is defined and the transition of that definition from one system to another in Protection One's new billing and monitoring system, referred to as MAS(R), or Monitored Automation Systems, which reports number of accounts on the basis of one for every location Protection One provides service even if it has separate contracts to provide multiple services at that location. Protection One anticipates further adjustments, which could be either positive or negative, from the conversion of its Portland, Maine monitoring station to MAS(R) in 2002. These conversions are substantially complete at the present time. Actual attrition experience shows that the relationship period with any individual customer can vary significantly. Customers discontinue service for a variety of reasons, including relocation, service issues and cost. A portion of the acquired customer base can be expected to discontinue service every year. Any significant change in the pattern of historical attrition experience would have a material effect on Monitored Services' results of operations. Attrition is monitored each quarter based on a quarterly annualized and trailing twelve-month basis. This method utilizes the average customer account base for the applicable period in measuring attrition. Therefore, in periods of customer account growth, customer attrition may be understated and in periods of customer account decline, customer attrition may be overstated. Customer attrition for the years ended December 31, 2001 and 2000 is summarized below. Customer Account Attrition ------------------------------------------- December 31, 2001 December 31, 2000 -------------------- --------------------- Annualized Trailing Annualized Trailing Fourth Twelve Fourth Twelve Quarter Month Quarter Month ---------- -------- ---------- --------- Protection One ..................... 18.1% 15.2% 15.0% 14.0% Protection One Europe (a) .......... 11.4% 10.9% 11.6% 10.9% - ---------- (a) United Kingdom operations were disposed of in June 2001. Our monitored services segment had a net decrease of 267,347 customers from December 31, 2000 to December 31, 2001. The number of customers decreased primarily because Monitored Services' customer acquisition strategies were not able to generate accounts in a sufficient volume at acceptable costs to replace 54
accounts lost through attrition. We expect that this trend will continue until the efforts being made to acquire new accounts at acceptable costs and reduce attrition become more successful than they have been to date. Until this trend has been reversed, net losses of customer accounts will materially and adversely affect monitored services' business, financial condition, results of operations and prospects. Related Party Transactions - -------------------------- Below we describe significant transactions between us and Westar Industries and other subsidiaries and related parties. We have disclosed significant transactions even if these have been eliminated in the preparation of our consolidated results and financial position since our proposed financial plan, as discussed in Note 15 in the "Notes to Consolidated Financial Statements," calls for a split-off of Westar Industries from us to occur in the future. We cannot predict whether the KCC will approve the plan and if so whether we will be successful in executing the plan. We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses. 2001 2000 1999 ------ ------ ------ (In Thousands) Charges to ONEOK ........................................ $8,202 $8,463 $8,876 Charges from ONEOK ...................................... 3,279 3,420 3,322 Net receivable from ONEOK, outstanding at December 31 ... 1,424 1,205 1,506 In 1999, we and Protection One entered into a service agreement pursuant to which we provide administrative services, including accounting, human resources, legal, facilities and technology services on a year to year basis. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $8.1 million in 2001, $7.3 million in 2000 and $2.0 million in 1999. These intercompany charges have been eliminated in consolidation. We had a payable to Westar Industries of approximately $67.7 million at December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On February 28, 2001, Westar Industries converted $350.0 million of the then outstanding payable balance into approximately 14.4 million shares of our common stock, representing 16.9% of our outstanding common stock after conversion. These shares are reflected as treasury stock in our consolidated balance sheets. During the first quarter of 2002, we repaid the remaining balance owed to Westar Industries. The proceeds were used by Westar Industries to purchase our outstanding debt in the open market. At February 28, 2002, Westar Industries owned $118.7 million of our debt. Amounts outstanding and interest earned by Westar Industries have been eliminated in our consolidated financial statements. See Note 2, "Summary of Significant Accounting Policies -- Principles of Consolidation" of the "Notes to Consolidated Financial Statements." Westar Industries is the lender under Protection One's senior credit facility. On November 1, 2001, this facility was amended to, among other things, extend the maturity date to January 3, 2003, and provide for a quarterly fee for financial advisory and management services equal to 1/8% of Protection One's consolidated total assets at the end of each quarter, beginning with the quarter ending March 31, 2002. As of March 14, 2002, approximately $145.5 million was drawn under the facility. On March 25, 2002, Westar Industries further amended the facility to increase the amount of the facility to $180 million. Amounts outstanding have been eliminated in our consolidated financial statements. We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes as long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $11.8 million for tax year 2001 and $7.4 million for tax year 2000 for the tax benefit. 55
During 2001, Westar Industries purchased $37.9 million face value of Protection One bonds on the open market. In October 2001, $27.6 million of these bonds were transferred to Protection One in exchange for cash. In 2001, we recognized an extraordinary gain from the purchase of Protection One bonds of $22.3 million, net of tax of $12.0 million. During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 million of these debt securities were transferred to Protection One. The balance of the bonds was sold to Protection One in March 2001. No gain or loss was recognized on these transactions. In the latter part of 2001 through February 28, 2002, Protection One purchased approximately $1.8 million of our preferred stock in open market purchases. These purchases have been accounted for as retirements. During 2001, we extended loans to our officers for the purpose of purchasing shares of our common stock on the open market. The loans are unsecured and contain a variable interest rate that is equal to our short term borrowing rate. Interest is payable quarterly. The loans mature and become due on December 4, 2004. The balance outstanding at December 31, 2001 was approximately $2.0 million and is classified as a reduction to shareholders' equity in the accompanying consolidated balance sheet. The maximum amount of loans authorized is $7.9 million. During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings. On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held be a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Westar Industries 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 Industries on Protection One's revolving credit facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected. If the KCC approves our financial plan, at the closing of the proposed rights offering, we would enter into an option agreement that grants Westar Industries an option to purchase the stock of Westar Generating, Inc., a wholly owned subsidiary that owns our interest in the State Line generating facility. The option would be exercisable at any time during the three year period following execution of the agreement, subject to extension for two additional one year periods. The option price is based on net book value at the time of exercise. The option would be exercisable only if Westar Industries is unable to obtain a permanent exemption from registration under the Investment Company Act of 1940. Other New Accounting Standards - ------------------------------ In July 2001, FASB issued SFAS No. 141, "Business Combinations." SFAS No. 141 establishes that all business combinations will be accounted for using the purchase method. Use of the pooling-of-interests method is no longer allowed. The provisions of SFAS No. 141 are effective for all business combinations initiated after June 30, 2001 and all business combinations accounted for using the purchase method for which the date of acquisition is July 1, 2001 or later. Market Risk Disclosure - ---------------------- Market Price Risks: We are exposed to market risk, including market changes, changes in commodity prices, equity instrument investment prices and interest rates. 56
Commodity Price Exposure: We engage in both trading and non-trading activities in our commodity price risk management activities. We trade electricity, coal, natural gas and oil. We utilize a variety of financial instruments, including forward contracts involving cash settlements or physical delivery of an energy commodity, options, swaps requiring payments (or receipt of payments) from counterparties based on the differential between specified prices for the related commodity and futures traded on electricity, natural gas and oil. We are involved in trading activities primarily to minimize risk from market fluctuations, capitalize on our market knowledge and enhance system reliability. Net open positions exist or are established due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we were exposed to the risk that fluctuating market prices could adversely impact our financial position or results from operations. In 2002, we expect to trade coal, natural gas and oil fossil fuel types as well as electricity. We manage and measure the exposure of our trading portfolio using a variance/covariance value-at-risk (VAR) model. VAR measures the total risk, in dollars, of our entire trading portfolio. VAR also measures how much capital we are willing to put at risk to conduct trades. VAR acts as a metric to gauge trading risk. VAR measures the worst expected loss over a given time interval under normal market conditions at a given confidence level. The VAR computations are based on an historical simulation, which utilizes price movements over a specified period to simulate forward price curves in the energy markets to estimate the size of future potential losses. The quantification of market risk using VAR methodologies represents a consistent measure of an estimate of reasonably possible net losses in earnings that would be recognized on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. In addition to VAR, we employ additional risk control processes such as stress testing, daily loss limits, and commodity position limits. We expect to use the same VAR model and control processes in 2002. 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. The calculation includes derivative commodity instruments used for both trading and risk management purposes. The high, low and average VAR amounts for 2001 were $5.3 million, $0.2 million and $2.4 million, respectively, and for 2000 were $0.7 million, $0.04 million and $0.3 million, respectively. The VAR amounts increased from 2000 due to the inclusion of additional trading and hedging activities in the VAR model during 2001. Prior to the January 1, 2001 adoption of SFAS No. 133, power marketing and natural gas contracts not designated as hedges were included in the VAR calculations. After January 1, 2001, we included asset-based transactions that did not qualify for hedge accounting treatment. Also in 2001, we began to trade coal in our asset-based portfolio. Excluded from the calculation is the gas hedge, which is discussed below in "-- Fair Value of Contracts -- Gas Hedge and Interest Rate Swap." We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks 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 market prices. From 2000 to 2001, we experienced a 2% decrease in the average price per MW of electricity purchased for utility operations. However, purchased power markets are volatile and if we were to have a 10% increase from 2001 to 2002, given the amount of power purchased for utility operations during 2001, we would have exposure of approximately $5.3 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices. 57
We use a mix of various fuel types, including coal and natural gas, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk, associated with this commodity type. However, from January 1, 2001 to December 31, 2001, we experienced a 10% increase in our average cost for natural gas purchased for utility operations, or an increase of $0.34 per MMBtu. The higher natural gas prices increased our total cost of gas purchased during 2001 by approximately $3.7 million, although we decreased the quantity burned by 5.0 million MMBtu. If we were to have a similar increase from 2001 to 2002, we would have exposure of approximately $4.1 million of operating income. Based on MMBtus of natural gas and fuel oil burned during 2001, we had exposure of approximately $6.5 million of operating income for a 10% change in average price paid per MMBtu. Due to the volatility of natural gas prices, past prices cannot be used to predict future prices. During the first quarter of 2001, spot market prices for western coal markets increased significantly. Although the spot market prices have fallen back to previous levels, the increase impacted fuel prices of coal received under contracts for the portion that was indexed to or purchased on the spot market. This affected and will continue to affect our inventory price of coal for our LaCygne Generating Station and Lawrence and Tecumseh Energy Centers. Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically year to year based on the individual fuel's availability, price, deliverability, unit outages and nuclear refueling. Our customers' electricity usage could also vary dramatically year to year based on the weather or other factors. Interest Rate Exposure: We have approximately $1.0 billion of variable rate debt and current maturities of fixed rate debt as of December 31, 2001. A 100 basis point change in each debt series' benchmark rate at December 31, 2001, used to set the rate for such series would impact net income on an annual basis by approximately $2.6 million after tax. Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge. Foreign Currency Exchange Rates: We have foreign operations with functional currencies other than the United States dollar. As of December 31, 2001, the unrealized loss on currency translation, presented as a separate component of shareholders' equity and reported within other comprehensive income, was approximately $3.8 million pretax. A 10% change in the currency exchange rates would have an immaterial effect on other comprehensive income. Decline in Equity Price Risk: During 2000, our balance in marketable securities declined approximately $173.2 million from December 31, 1999, due to the sale of a significant portion of our marketable security portfolio. Since we no longer have a significant amount invested in marketable securities, we do not expect to be materially impacted by changes in the market prices of our remaining investments. Hedging Activity: We also use financial instruments to hedge a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine what the value will be when the agreements are actually settled. 58
In an effort to mitigate fuel commodity price market risk, we use hedging arrangements to minimize our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent upon the market prices and the extent and effectiveness of any hedging arrangements we enter. During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are using futures and swap contracts with a total notional volume of 39,000,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133. The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for 2001: Total Natural gas Interest Rate Cash Flow Hedge (a) Swap Hedges ----------- ------------- --------- (Dollars in Thousands) Fair value of derivative instruments: Current ............................................ $(9,988) $ -- $(9,988) Long-term .......................................... (8,844) (2,656) (11,500) -------- -------- -------- Total .......................................... $(18,832) $ (2,656) $(21,488) ======== ======== ======== Amounts in accumulated other comprehensive income ....... $(29,079) $ (2,656) $(31,735) Hedge ineffectiveness ................................... 2,551 -- 2,551 Estimated income tax benefit ............................ 10,552 1,057 11,609 -------- -------- -------- Net Comprehensive Loss ......................... $(15,976) $ (1,599) $(17,575) ======== ======== ======== Anticipated reclassifications to earnings during 2002 (b) $ 9,988 $ -- $ 9,988 Duration of hedge designation as of December 31, 2001 ... 31 months 22 months -- - ---------- (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices have dropped since we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place. (b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions. Fair Value of Energy Trading Contracts - -------------------------------------- The tables below show the difference between the market value and the notional values of energy trading contracts outstanding at December 31, 2001, their sources and maturity periods: Fair Value of Contracts (In Thousands) Net fair value of contracts outstanding at the beginning of the period........ $ 39,520 Contracts realized or otherwise settled during the period..................... (24,732) Fair value of new contracts entered into during the period.................... (12,479) --------- Fair value of contracts outstanding at the end of the period.................. $ 2,309 ========= 59
Fair Value of Contracts at End of Period ------------------------------------------------------------- Maturity Maturity in Total Less Than Maturity Maturity Excess of Source of Fair Value Fair Value 1 Year 1-3 Years 4-5 Years 5 Years ---------- --------- --------- --------- ----------- (In Thousands) Prices actively quoted (futures) ...................... $ (422) $ 160 $ (582) $ -- $ -- Prices provided by other external sources (swaps and forwards) ........................................ (2,060) (2,028) (32) -- -- Prices based on models and other valuation models (options and other) .............................. 4,791 5,495 (704) -- -- -------- -------- -------- -------- -------- Total fair value of contracts outstanding ............. $ 2,309 $ 3,627 $ (1,318) $ -- $ -- ======== ======== ======== ======== ======== ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - ------------------------------------------------------------------- Information relating to market risk disclosure is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information" included herein. 60
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - --------------------------------------------------- TABLE OF CONTENTS PAGE Report of Independent Public Accountants................................ 62 Financial Statements: Western Resources, Inc. and Subsidiaries: Consolidated Balance Sheets, December 31, 2001 and 2000..... 63 Consolidated Statements of Income (Loss) for the years ended December 31, 2001, 2000 and 1999................ 64 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2001, 2000 and 1999...... 65 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999...................... 66 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999.......... 67 Notes to Consolidated Financial Statements........................ 68 Financial Schedules: Schedule II - Valuation and Qualifying Accounts................... 119 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 our consolidated financial statements and schedules presented: I, III, IV, and V. 61
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Western Resources, Inc.: We have audited the accompanying consolidated balance sheets of Western Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, 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, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Resources, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. Schedule II - Valuation and Qualifying Accounts is presented for purposes of complying with the Securities and Exchange Commission rules and is not part of the basic financial statements. The schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Kansas City, Missouri, March 27, 2002 62
WESTERN RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (Dollars in Thousands) December 31, --------------------------- 2001 2000 ----------- ----------- ASSETS CURRENT ASSETS: Cash and cash equivalents ................................................................. $ 96,691 $ 8,762 Restricted cash ........................................................................... 14,795 10,915 Accounts receivable, net .................................................................. 112,864 152,165 Inventories and supplies, net ............................................................. 145,099 101,303 Energy trading contracts .................................................................. 71,421 185,364 Deferred tax assets ....................................................................... 27,817 34,512 Prepaid expenses and other ................................................................ 41,331 43,049 ----------- ----------- Total Current Assets ............................................................... 510,018 536,070 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET ............................................................. 4,042,852 3,993,438 ----------- ----------- OTHER ASSETS: Restricted cash ........................................................................... 38,515 47,168 Investment in ONEOK ....................................................................... 598,929 591,173 Customer accounts, net .................................................................... 830,708 1,005,505 Goodwill, net ............................................................................. 884,786 976,102 Regulatory assets ......................................................................... 358,025 327,350 Energy trading contracts .................................................................. 15,247 15,883 Other ..................................................................................... 233,985 309,031 ----------- ----------- Total Other Assets ................................................................. 2,960,195 3,272,212 ----------- ----------- TOTAL ASSETS ................................................................................... $ 7,513,065 $ 7,801,720 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt ...................................................... $ 160,576 $ 41,825 Short-term debt ........................................................................... 222,300 35,000 Accounts payable .......................................................................... 125,285 154,654 Accrued liabilities ....................................................................... 181,671 206,959 Accrued income taxes ...................................................................... 39,770 53,834 Deferred security revenues ................................................................ 48,461 73,585 Energy trading contracts .................................................................. 67,859 191,673 Other ..................................................................................... 57,459 56,600 ----------- ----------- Total Current Liabilities .......................................................... 903,381 814,130 ----------- ----------- LONG-TERM LIABILITIES: Long-term debt, net ....................................................................... 2,978,382 3,237,849 Western Resources obligated mandatorily redeemable preferred securities of subsidiary trusts holding solely company subordinated debentures .................................. 220,000 220,000 Deferred income taxes and investment tax credits .......................................... 924,178 954,595 Minority interests ........................................................................ 166,850 184,591 Deferred gain from sale-leaseback ......................................................... 174,466 186,294 Energy trading contracts .................................................................. 16,500 1,096 Other ..................................................................................... 285,247 271,745 ----------- ----------- Total Long-Term Liabilities ........................................................ 4,765,623 5,056,170 ----------- ----------- COMMITMENTS AND CONTINGENCIES (NOTE 14) SHAREHOLDERS' EQUITY: Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued 248,576 shares; outstanding 239,364 shares and 248,576 shares, respectively ............ 23,936 24,858 Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,205,417 shares and 70,082,314 shares, respectively ............................................. 431,027 350,412 Paid-in capital ........................................................................... 1,196,763 868,166 Unearned compensation ..................................................................... (21,920) (18,066) Loans to officers ......................................................................... (1,973) -- Retained earnings ......................................................................... 606,502 714,454 Treasury stock, at cost, 15,097,987 and 0 shares, respectively ............................ (364,901) -- Accumulated other comprehensive loss, net ................................................. (25,373) (8,404) ----------- ----------- Total Shareholders' Equity ......................................................... 1,844,061 1,931,420 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ..................................................... $ 7,513,065 $ 7,801,720 =========== =========== The accompanying notes are an integral part of these consolidated financial statements. 63
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Dollars in Thousands, Except Per Share Amounts) Year Ended December 31, ---------------------------------------------- 2001 2000 1999 ------------ ------------ ------------ SALES: Energy ...................................................................... $ 1,768,393 $ 1,829,133 $ 1,429,698 Monitored Services .......................................................... 417,869 539,343 600,389 ------------ ------------ ------------ Total Sales ...................................................... 2,186,262 2,368,476 2,030,087 ------------ ------------ ------------ COST OF SALES: Energy ...................................................................... 855,292 850,018 478,837 Monitored Services .......................................................... 144,258 185,814 180,109 ------------ ------------ ------------ Total Cost of Sales .............................................. 999,550 1,035,832 658,946 ------------ ------------ ------------ GROSS PROFIT ................................................................... 1,186,712 1,332,644 1,371,141 ------------ ------------ ------------ OPERATING EXPENSES: Operating and maintenance ................................................... 349,413 337,481 337,081 Depreciation and amortization ............................................... 413,642 426,369 403,669 Selling, general and administrative ......................................... 334,862 343,163 334,977 Dispositions of monitored services operations ............................... 13,056 -- -- Merger costs ................................................................ 8,693 -- 17,600 ------------ ------------ ------------ Total Operating Expenses ......................................... 1,119,666 1,107,013 1,093,327 ------------ ------------ ------------ INCOME FROM OPERATIONS ......................................................... 67,046 225,631 277,814 ------------ ------------ ------------ OTHER INCOME (EXPENSE): Investment earnings ......................................................... 52,634 192,423 35,979 Impairment of investments ................................................... (11,075) -- (76,166) Minority interests .......................................................... 11,621 8,625 12,600 Other ....................................................................... 4,397 -- 14,234 ------------ ------------ ------------ Total Other Income (Expense) ..................................... 57,577 201,048 (13,353) ------------ ------------ ------------ EARNINGS BEFORE INTEREST AND TAXES ............................................. 124,623 426,679 264,461 ------------ ------------ ------------ INTEREST EXPENSE: Interest expense on long-term debt .......................................... 227,601 226,419 236,417 Interest expense on short-term debt and other ............................... 40,623 63,149 57,687 ------------ ------------ ------------ Total Interest Expense ........................................... 268,224 289,568 294,104 ------------ ------------ ------------ EARNINGS (LOSS) BEFORE INCOME TAXES ............................................ (143,601) 137,111 (29,643) Income tax expense (benefit) ................................................... (80,875) 46,061 (32,197) ------------ ------------ ------------ NET INCOME (LOSS) BEFORE EXTRAORDINARY GAIN AND ACCOUNTING CHANGE .............. (62,726) 91,050 2,554 Extraordinary gain, net of tax of $12,571, $26,514, and $6,322 ................. 23,156 49,241 11,742 Cumulative effect of accounting change, net of tax of $12,347 and $1,097 ....... 18,694 (3,810) -- ------------ ------------ ------------ NET INCOME (LOSS) .............................................................. (20,876) 136,481 14,296 Preferred dividends ............................................................ 895 1,129 1,129 ------------ ------------ ------------ EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK ..................................... $ (21,771) $ 135,352 $ 13,167 ============ ============ ============ Average common shares outstanding .............................................. 70,649,969 68,962,245 67,080,281 BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARES OUTSTANDING: Basic and diluted earnings (losses) available before extraordinary gain and accounting change .................................................... $ (0.90) $ 1.30 $ 0.02 Extraordinary gain, net of tax .............................................. 0.33 0.71 0.18 Accounting change, net of tax ............................................... 0.26 (0.05) -- ------------ ------------ ------------ Basic and diluted earnings (losses) available after extraordinary gain and accounting change ........................................................ $ (0.31) $ 1.96 $ 0.20 ============ ============ ============ DIVIDENDS DECLARED PER COMMON SHARE ............................................ $ 1.20 $ 1.435 $ 2.14 The accompanying notes are an integral part of these consolidated financial statements. 64
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Dollars in Thousands) Year Ended December 31, ----------------------------------------------------------------------- 2001 2000 1999 --------------------- --------------------- --------------------- NET INCOME (LOSS) ..................................... $ (20,876) $ 136,481 $ 14,296 --------- --------- --------- OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: Unrealized holding (losses) gains on marketable securities arising during the period .......... $ (592) $ 43,174 $ (55,420) Adjustment for losses (gains) included in net income ........................................ 3,336 2,744 (114,948) (71,774) 102,417 46,997 --------- --------- --------- Unrealized holding losses on cash flow hedges arising during the period ..................... (31,735) -- -- Adjustment for losses included in net income ...... 2,551 (29,184) -- -- -- -- --------- --------- --------- Minimum pension liability adjustment ............. (6,712) -- -- Foreign currency translation adjustment .......... 2,568 (9,376) (115) Income tax benefit ............................... 13,615 34,958 (18,602) --------- --------- --------- Total other comprehensive (loss) gain, net of tax ............................. (16,969) (46,192) 28,280 --------- --------- --------- COMPREHENSIVE INCOME (LOSS) ........................... $ (37,845) $ 90,289 $ 42,576 ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements. 65
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in Thousands) Year Ended December 31, ----------------------------------- 2001 2000 1999 --------- --------- --------- CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net income (loss) ........................................................ $ (20,876) $ 136,481 $ 14,296 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Extraordinary gain ....................................................... (23,156) (49,241) (11,742) Cumulative effect of accounting change ................................... (18,694) 3,810 -- Depreciation and amortization ............................................ 413,642 426,369 403,669 Amortization of deferred gain from sale-leaseback ........................ (11,828) (11,828) (11,828) Net changes in energy trading assets and liabilities ..................... 6,552 7,497 (1,188) Equity in earnings from investments ...................................... (4,721) (11,219) (8,199) Loss on dispositions of monitored services operations .................... 13,056 -- -- Impairment on investments ................................................ 11,075 -- 76,166 (Gain) loss on sale of marketable securities ............................. 1,861 (114,948) 26,251 Minority interests ....................................................... (11,621) (8,625) (12,600) Gain on sale of investments .............................................. -- (9,562) (17,249) Accretion of discount note interest ...................................... (2,247) (6,237) (6,799) Net deferred taxes ....................................................... (35,024) (29,744) (15,825) Deferred merger costs .................................................... 8,693 -- 17,600 Changes in working capital items, net of acquisitions and dispositions: Restricted cash ...................................................... (3,880) (22,630) (16,154) Accounts receivable, net ............................................. 36,213 77,873 (3,824) Inventories and supplies, net ........................................ (45,572) 12,282 (15,024) Prepaid expenses and other ........................................... 231 (10,314) (2,571) Accounts payable ..................................................... (26,865) 44,172 5,000 Accrued liabilities .................................................. (19,783) (19,457) (20,152) Accrued income taxes ................................................. (14,064) 13,506 7,386 Deferred security revenues ........................................... (8,154) (2,065) 3,479 Changes in other assets and liabilities .................................. (20,006) (14,358) (42,251) --------- --------- --------- Cash flows from operating activities ........................ 224,832 411,762 368,441 --------- --------- --------- CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Additions to property, plant and equipment, net .......................... (236,452) (308,073) (275,744) Customer account acquisitions ............................................ (36,488) (35,513) (241,000) Security alarm monitoring acquisitions, net of cash acquired ............. -- (11,748) (27,409) Purchases of marketable securities ....................................... -- -- (12,003) Proceeds from sale of marketable securities .............................. 2,829 218,609 73,456 Proceeds from dispositions of monitored services operations .............. 47,974 -- -- Proceeds from sale of other investments, net of purchases ................ 60,725 50,688 15,556 --------- --------- --------- Cash flows used in investing activities ..................... (161,412) (86,037) (467,144) --------- --------- --------- CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Short-term debt, net ..................................................... 188,907 (670,421) 392,949 Proceeds of long-term debt ............................................... 26,925 610,045 16,000 Retirements of long-term debt ............................................ (128,997) (208,952) (198,021) Issuance of officer loans ................................................ (1,973) -- -- Issuance of common stock, net ............................................ 19,384 27,441 43,245 Cash dividends paid ...................................................... (85,547) (98,827) (145,033) Preferred stock redemption ............................................... (547) -- -- Acquisition of treasury stock ............................................ (866) (9,187) (15,791) Reissuance of treasury stock ............................................. 7,223 21,898 -- --------- --------- --------- Cash flows from (used in) financing activities .............. 24,509 (328,003) 93,349 --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .......................... 87,929 (2,278) (5,354) CASH AND CASH EQUIVALENTS: Beginning of period ...................................................... 8,762 11,040 16,394 --------- --------- --------- End of period ............................................................ $ 96,691 $ 8,762 $ 11,040 ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements. 66
WESTERN RESOURCES, INC. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Dollars in Thousands) Cumulative Preferred and Preference Common Paid-in Unearned Loans to Retained Stock Stock Capital Compensation Officers Earnings ------------- -------- ---------- ------------ -------- --------- BALANCE, December 31, 1998 ......... $ 24,858 $329,548 $ 777,401 $ (2,064) $ -- $ 810,617 Net income ......................... -- -- -- -- -- 14,296 Dividends on preferred and preference stock ................. -- -- -- -- -- (1,129) Issuance of common stock ........... -- 11,960 44,906 -- -- -- Dividends on common stock .......... -- -- -- -- -- (143,904) Unrealized gain on marketable securities ....................... -- -- -- -- -- -- Currency translation adjustment .... -- -- -- -- -- -- Tax benefit ........................ -- -- -- -- -- -- Acquisition of treasury stock ...... -- -- -- -- -- -- Grant of restricted stock .......... -- -- 4,333 (4,333) -- -- Amortization of restricted stock ... -- -- -- 702 -- -- -------------------------------------------------------------------------------- BALANCE, December 31, 1999 ......... $ 24,858 $341,508 $ 826,640 $ (5,695) $ -- $ 679,880 Net income ......................... -- -- -- -- -- 136,481 Dividends on preferred and preference stock ................. -- -- -- -- -- (1,129) Issuance of common stock ........... -- 8,904 18,537 -- -- -- Dividends on common stock .......... -- -- -- -- -- (97,698) Unrealized loss on marketable securities ....................... -- -- -- -- -- -- Currency translation adjustment .... -- -- -- -- -- -- Tax benefit ........................ -- -- -- -- -- -- Acquisition of treasury stock ...... -- -- -- -- -- -- Issuance of treasury stock ......... -- -- -- -- -- (3,080) Grant of restricted stock .......... -- -- 22,989 (22,989) -- -- Amortization of restricted stock ... -- -- -- 10,618 -- -- -------------------------------------------------------------------------------- BALANCE, December 31, 2000 ......... $ 24,858 $350,412 $ 868,166 $(18,066) $ -- $ 714,454 Net income ......................... -- -- -- -- -- (20,876) Dividends on preferred and preference stock ................. -- -- -- -- -- (1,129) Issuance of common stock ........... -- 80,615 298,236 -- -- -- Dividends on common stock .......... -- -- -- -- -- (84,474) Retirement of preferred stock ...... (922) -- -- -- -- 375 Issuance of officer loans .......... -- -- -- -- (1,973) -- Unrealized gain on marketable securities ....................... -- -- -- -- -- -- Unrealized loss on cash flow hedges ............................. -- -- -- -- -- -- Minimum pension liability adjustment -- -- -- -- -- -- Currency translation adjustment .... -- -- -- -- -- -- Tax benefit ........................ -- -- -- -- -- (141) Acquisition of treasury stock ...... -- -- -- -- -- -- Issuance of treasury stock ......... -- -- -- -- -- (1,707) Cancellation of restricted stock ... -- -- 14,570 -- -- -- Grant of restricted stock .......... -- -- 15,791 (15,791) -- -- Amortization of restricted stock ... -- -- -- 11,937 -- -- -------------------------------------------------------------------------------- BALANCE, December 31, 2001 ......... $ 23,936 $431,027 $1,196,763 $(21,920) $(1,973) $ 606,502 ================================================================================ Accumulated Other Treasury Comprehensive Stock Income Total --------- ------------- ----------- BALANCE, December 31, 1998 ......... $ -- $ 9,508 $ 1,949,868 Net income ......................... -- -- 14,296 Dividends on preferred and preference stock ................. -- -- (1,129) Issuance of common stock ........... -- -- 56,866 Dividends on common stock .......... -- -- (143,904) Unrealized gain on marketable securities ....................... -- 46,997 46,997 Currency translation adjustment .... -- (115) (115) Tax benefit ........................ -- (18,602) (18,602) Acquisition of treasury stock ...... (15,791) -- (15,791) Grant of restricted stock .......... -- -- -- Amortization of restricted stock ... -- -- 702 ---------------------------------------- BALANCE, December 31, 1999 ......... $ (15,791) $ 37,788 $ 1,889,188 Net income ......................... -- -- 136,481 Dividends on preferred and preference stock ................. -- -- (1,129) Issuance of common stock ........... -- -- 27,441 Dividends on common stock .......... -- -- (97,698) Unrealized loss on marketable securities ....................... -- (71,774) (71,774) Currency translation adjustment .... -- (9,376) (9,376) Tax benefit ........................ -- 34,958 34,958 Acquisition of treasury stock ...... (9,187) -- (9,187) Issuance of treasury stock ......... 24,978 -- 21,898 Grant of restricted stock .......... -- -- -- Amortization of restricted stock ... -- -- 10,618 ---------------------------------------- BALANCE, December 31, 2000 ......... $ -- $ (8,404) $ 1,931,420 Net income ......................... -- -- (20,876) Dividends on preferred and preference stock ................. -- -- (1,129) Issuance of common stock ........... (358,805) -- 20,046 Dividends on common stock .......... -- -- (84,474) Retirement of preferred stock ...... -- -- (547) Issuance of officer loans .......... -- -- (1,973) Unrealized gain on marketable securities ....................... -- 2,744 2,744 Unrealized loss on cash flow hedges ............................. -- (29,184) (29,184) Minimum pension liability adjustment -- (6,712) (6,712) Currency translation adjustment .... -- 2,568 2,568 Tax benefit ........................ -- 13,615 13,474 Acquisition of treasury stock ...... (866) -- (866) Issuance of treasury stock ......... 9,340 -- 7,633 Cancellation of restricted stock ... (14,570) -- -- Grant of restricted stock .......... -- -- -- Amortization of restricted stock ... -- -- 11,937 ---------------------------------------- BALANCE, December 31, 2001 ......... $(364,901) $(25,373) $ 1,844,061 ======================================== The accompanying notes are an integral part of these consolidated financial statements. 67
WESTERN RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. DESCRIPTION OF BUSINESS Western Resources, Inc. is a publicly traded consumer services company incorporated in 1924 in the State of Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the company," "Western Resources," "we," "us," "our" or similar words are to Western Resources, Inc., and its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 640,000 customers in Kansas and monitored security services to over 1.2 million customers in North America and Europe. ONEOK, Inc. (ONEOK), in which we have an approximate 45% ownership interest, provides natural gas transmission and distribution services to approximately 1.4 million customers in Oklahoma and Kansas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612. We and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service using the name Westar Energy. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek). Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK, Inc. and other non-utility businesses. Protection One, a publicly traded, approximately 87% -owned subsidiary, and Protection One Europe provide monitored security services. Protection One Europe refers collectively to Protection One International, Inc., a wholly owned subsidiary of Westar Industries, and its subsidiaries, including a French subsidiary in which it owns approximately a 99.8% interest. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation - --------------------------- We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (GAAP). Our consolidated financial statements include all operating divisions and majority owned subsidiaries for which we maintain controlling interests. Common stock investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation. Use of Management's Estimates - ----------------------------- The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulatory Accounting - --------------------- We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. 68
Cash and Cash Equivalents - ------------------------- We consider highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. Restricted Cash - --------------- Restricted cash consists of cash used to collateralize letters of credit and cash held in escrow, primarily related to supporting our power trading transactions. Inventories and Supplies - ------------------------ Inventories and supplies for our utility business are stated at average cost. Inventories for our monitored services segment, comprised of alarm systems and parts, are stated at the lower of average cost or market. Property, Plant and Equipment - ----------------------------- Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision, and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction projects. The AFUDC rate was 9.01% in 2001, 7.39% in 2000 and 6.00% in 1999. The cost of additions to utility plant and replacement units of property are capitalized. Interest capitalized into construction in progress was $8.7 million in 2001, $9.4 million in 2000 and $4.4 million in 1999. Maintenance costs and replacement of minor items of property are charged to expense as incurred. Incremental costs incurred during scheduled Wolf Creek refueling and maintenance outages are deferred and amortized monthly over the unit's operating cycle, normally about 18 months. For utility plant, 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 for the KGE acquisition totaled $128.3 million as of December 31, 2001 and $108.2 million as of December 31, 2000. Depreciation - ------------ Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 3.03% during 2001, 2.99% during 2000 and 2.92% during 1999. In its rate order of July 25, 2001, the KCC extended the recovery period for our generating assets, including Wolf Creek, for regulatory rate making purposes. The impact of this decision reduced our retail electric rates by approximately $17.6 million on an annual basis. We intend to file an application for an accounting authority order with the KCC to allow the creation of a regulatory asset for the difference between our book and regulatory depreciation. We cannot predict whether the KCC will approve our application. Non-utility property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the related assets. We periodically evaluate our depreciation rates considering the past and expected future experience in the operation of our facilities. 69
Depreciable lives of property, plant and equipment are as follows: Utility: Fossil generating facilities.................... 10 to 48 years Nuclear generating facilities................... 38 years Transmission facilities......................... 27 to 65 years Distribution facilities......................... 14 to 65 years Other........................................... 3 to 50 years Non-utility: Buildings....................................... 40 years Installed systems............................... 10 years Furniture, fixtures and equipment............... 5 to 10 years Leasehold improvements.......................... 5 to 10 years Vehicles........................................ 5 years Data processing and telecommunications.......... 1 to 7 years Nuclear Fuel - ------------ Our share of the cost of nuclear fuel in process of refinement, conversion, enrichment and fabrication is recorded as an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to cost of sales based upon the quantity of heat produced for the generation of electricity. The accumulated amortization of nuclear fuel in the reactor was $35.6 million at December 31, 2001 and $18.6 million at December 31, 2000. Spent fuel charged to cost of sales was $22.1 million in 2001, $19.6 million in 2000 and $20.1 million in 1999. 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. Prior to the third quarter of 1999, Protection One and Protection One Europe amortized their 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 was applied. The choice of an amortization life was based on estimates and judgments about the amounts and timing of expected future revenues from these assets and average customer account life. Selected periods were determined because, in Protection One's and Protection One Europe's opinion, they would adequately match amortization cost with anticipated revenue. Protection One and Protection One Europe conducted a comprehensive review of their amortization policy during the third quarter of 1999, prior to Westar Industries' acquisition of Protection One Europe. As a part of this review, Protection One and Protection One Europe hired an independent appraisal firm to perform a lifing study on customer accounts. 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 had distinct attributes that effect differing attrition characteristics. The pools corresponded to Protection One's North America, Multifamily and Europe business segments. For the North America and Europe pools, the results of the lifing study indicated that Protection One could 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 estimated revenue stream from these assets. Protection One and Protection One Europe elected to change to that method, except for Protection One accounts acquired in the Westinghouse acquisition that were utilizing an eight-year accelerated method. No change was made in the method used for the Multifamily pool. 70
Protection One's and Protection One Europe'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 customers......................... 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 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, GAAP requires 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 the North America customers that 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 approximately $40 million. Accumulated amortization would have been approximately $34 million higher through the end of the second quarter of 1999 if the declining balance method had been used historically. 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 and Protection One Europe 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 related goodwill. See Note 25 below for information regarding SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," which replaces SFAS No. 121 as of January 1, 2002. Goodwill has been recorded in business acquisitions where the principal asset acquired was the recurring revenues from the acquired customer base. For purposes of the impairment analysis, goodwill has been considered directly related to the acquired customers. Due to the customer attrition experienced in 2001, 2000 and 1999, the decline in market value of Protection One's publicly traded equity and debt securities and because of recurring losses, Protection One and Protection One Europe performed impairment tests on their customer account assets and goodwill in 2001, 2000 and 1999. These tests indicated that future estimated undiscounted cash flows exceeded the sum of the recorded balances for customer accounts and goodwill. See Note 25 below for information regarding an impairment recorded in 2002 pursuant to new accounting rules. Goodwill - -------- Goodwill represents the excess of the purchase price over the fair value of net assets acquired by Protection One and Protection One Europe. Protection One and Protection One Europe changed their estimated goodwill life from 40 years to 20 years as of January 1, 2000. After that date, remaining goodwill, net of accumulated amortization, is being amortized over its remaining useful life based on a 20-year life. As a result of this change in estimate, goodwill amortization expense for the year ended December 31, 2000 increased by approximately $33.0 million. The resulting reduction to net income for 2000 was $26.1 million or a decrease in earnings per share of $0.38. 71
The carrying value of goodwill was included in the evaluations of recoverability of customer accounts. No reduction in the carrying value was necessary at December 31, 2001 or 2000. Goodwill accumulated amortization was $170.0 million at December 31, 2001 and $118.6 million at December 31, 2000. Goodwill amortization expense was $57.1 million for the year ended 2001, $61.4 million for 2000 and $31.6 million for 1999. Beginning January 1, 2002, goodwill will no longer be amortized. New accounting rules to be adopted on January 1, 2002 do not permit goodwill amortization and require an annual impairment test. See Note 25 below for information regarding an impairment recorded in 2002 pursuant to new accounting rules. Regulatory Assets and Liabilities - --------------------------------- Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. We have recorded these regulatory assets and liabilities in accordance with SFAS No. 71. If we were required to terminate application of SFAS No. 71 for all of our regulated operations, we would have to record the amounts of all regulatory assets and liabilities in our consolidated statements of income at that time. Our earnings would be reduced by the total amount in the table below, net of applicable income taxes. Regulatory assets and liabilities reflected in our consolidated financial statements are as follows: As of December 31, ------------------------ 2001 2000 -------- -------- (In Thousands) Recoverable income taxes ....................... $221,373 $187,308 Debt issuance costs ............................ 58,054 63,263 Deferred employee benefit costs ................ 32,687 36,251 Deferred plant costs ........................... 29,499 29,921 Other regulatory assets ........................ 16,412 10,607 -------- -------- Total regulatory assets ................... $358,025 $327,350 ======== ======== Total regulatory liabilities .............. $ 6,037 $ 1,978 ======== ======== . 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 represent post-retirement and post-employment expenses in excess of amounts paid that are to be recovered over a period of five years as authorized by the KCC. . Deferred plant costs: Costs related to the Wolf Creek nuclear generating facility. We expect to recover all of the above regulatory assets in rates charged to customers. A return is allowed on deferred plant costs and coal contract settlement costs (included in "Other regulatory assets" in the table above). 72
Cash Surrender Value of Life Insurance - -------------------------------------- The following amounts related to corporate-owned life insurance policies (COLI) are recorded in other long-term assets on our consolidated balance sheets at December 31: 2001 2000 ------ ------ (In Millions) Cash surrender value of policies (a) ................... $772.8 $705.4 Borrowings against policies ............................ (723.6) (665.9) ------ ------ COLI, net ........................................ $ 49.2 $ 39.5 ====== ====== - ---------- (a) Cash surrender value of policies as presented represents the value of the policies as of the end of the respective policy years and not as of December 31, 2001 and 2000. Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as other income approximated $2.7 million in 2001, $0.9 million in 2000 and $1.4 million in 1999. Minority Interests - ------------------ Minority interests represent the minority shareholders' proportionate share of the shareholders' equity and net loss of Protection One and Protection One Europe. Revenue Recognition - ------------------- Energy Sales: Energy sales are recognized as services are rendered and include an estimate for energy delivered but unbilled at the end of each year, except for power marketing. Power marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales in our consolidated statements of income. The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheet. We primarily use quoted market prices to value our power marketing and energy trading contracts. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The market prices used to value these transactions reflect our best estimate considering various factors, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. Results actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results. Financially settled trading transactions are reported on a net basis, reflecting the financial nature of these transactions. Physically settled trading transactions are recorded on a gross basis in operating revenues and fuel and purchased power expense. Monitored Services Revenues: Monitored services revenues are recognized when security services are provided. Installation revenue, sales revenues on equipment upgrades and direct costs of installations and sales are deferred for residential customers with service contracts. For commercial customers and national account customers, revenue recognition is dependent upon each specific customer contract. In instances when the company sells the equipment outright, revenues and costs are recognized in the period incurred. In cases where there is no outright sale, revenues and direct costs are deferred and amortized. 73
Deferred installation revenues and system sales revenues will be recognized over the expected useful life of the customer. Deferred costs in excess of deferred revenues will be recognized over the contract life. To the extent deferred costs are less than deferred revenues, such costs are recognized over the customers' estimated useful life. Deferred revenues also result from customers who are billed for monitoring, extended service protection and patrol and response services in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. Income Taxes - ------------ Our consolidated financial statements use the liability method to reflect income taxes. Deferred tax assets and liabilities are recognized for temporary differences in amounts recorded for financial reporting purposes and their respective tax bases. We amortize deferred investment tax credits over the lives of the related properties. Foreign Currency Translation - ---------------------------- The assets and liabilities of our foreign operations are translated into United States dollars at current exchange rates and revenues and expenses are translated at average exchange rates for the year. Cumulative Effects of Accounting Changes - ---------------------------------------- Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in fossil fuel purchases and electricity sales. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheet as either an asset or liability measured at fair value. Changes in a derivative's fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Cash flows from derivative instruments are presented in net cash flows from operating activities. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Prior to January 1, 2001, gains and losses on our derivatives used for managing commodity price risk were deferred until settlement. These derivatives were not designated as hedges under SFAS No. 133. Accordingly, on January 1, 2001, we recognized an unrealized gain of $18.7 million, net of $12.3 million of tax. This gain is presented on our consolidated statement of income as a cumulative effect of a change in accounting principle. After January 1, 2001, changes in fair value of all derivative instruments used for managing commodity price risk that are not designated as hedges are recognized in revenue as discussed above under "-- Revenue Recognition -- Energy Sales." Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings. In the fourth quarter of 2000, we adopted Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition," which had a retroactive effective date of January 1, 2000. The impact of this accounting change generally required deferral of certain monitored security services sales for installation revenues and direct sales-related expenses. Deferral of these revenues and costs is generally necessary when installation revenues have been received and a monitoring contract to provide future service is obtained. The cumulative effect of the change in accounting principle was approximately $3.8 million, net of tax benefits of $1.1 million and is related to changes in revenue recognition at Protection One Europe. Prior to the adoption of SAB No. 101, Protection One Europe recognized installation revenues and related expenses upon completion of the installation. 74
Supplemental Cash Flow Information - ---------------------------------- Cash paid for interest and income taxes for each of the years ended December 31, are as follows: 2001 2000 1999 -------- -------- -------- (In Thousands) Interest on financing activities, net of amount capitalized .... $306,865 $310,345 $298,802 Income taxes ................................................... 5,811 28,751 784 Reclassifications - ----------------- Certain amounts in prior years have been reclassified to conform with classifications used in the current year presentation. 3. RATE MATTERS AND REGULATION KCC Rate Proceedings - -------------------- On November 27, 2000, we and KGE filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our combined electric rates of $22.7 million, consisting of a $41.2 million reduction in KGE's rates and an $18.5 million increase in our rates. On August 9, 2001, we and KGE filed petitions with the KCC requesting reconsideration of the July 25, 2001 order. The petitions specifically asked for reconsideration of changes in depreciation, reductions in rate base related to deferred income taxes associated with the KGE acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2, wholesale revenue imputation and several other issues. On September 5, 2001, the KCC issued an order in response to our motions for reconsideration that increased our rate increase by an additional $7.0 million. The $41.2 million rate reduction in KGE's rates remained unchanged. On November 9, 2001, we filed an appeal of the KCC decisions with the Kansas Court of Appeals in an action captioned "Western Resources, Inc. and Kansas Gas and Electric Company vs. The State Corporation Commission of the State of Kansas." On March 8, 2002, the Court of Appeals upheld the KCC orders. We are evaluating whether to appeal this decision to the Kansas Supreme Court. KCC Investigation and Order - --------------------------- See Note 15 for a discussion of the order issued by the KCC on July 20, 2001 in the KCC's docket investigating the proposed separation of our electric utility businesses from our non-utility businesses and other aspects of our unregulated businesses. FERC Proceedings - ---------------- On September 12, 2001, we filed a settlement between the Federal Energy Regulatory Commission (FERC) staff and Westar Generating, Inc. (Westar Generating), the wholly owned subsidiary that owns our interests in the State Line generating facility. The settlement establishes the rate at which we will buy power from Westar Generating. FERC has jurisdiction over the establishment of this rate because of our affiliate relationship with Westar Generating. We continue to work toward a global settlement with the KCC, the only other active party, but can make no assurance on a resolution. In September 1999, the City of Wichita filed a complaint with FERC against us alleging improper affiliate transactions between our KPL division and KGE. The City of Wichita asked that FERC equalize the generation costs between KPL and KGE, in addition to other matters. After hearings on the case, a FERC administrative law judge ruled in our favor confirming that no change in rates was required. On December 13, 2000, the City of Wichita filed a brief with FERC asking that the Commission overturn the judge's decision. On January 5, 2001, we 75
filed a brief opposing the City's position. On November 23, 2001, FERC issued an order affirming the judge's decision. The City of Wichita's time to appeal FERC's order has expired. 4. ACCOUNTS RECEIVABLE Our accounts receivable on our consolidated balance sheets are comprised as follows: December 31, ------------------------- 2001 2000 --------- --------- (In Thousands) Gross accounts receivable ...................... $ 189,254 $ 254,743 Allowance for uncollectable accounts (a) ....... (19,121) (45,816) Unbilled energy receivables .................... 42,731 58,238 Accounts receivable sale program ............... (100,000) (115,000) --------- --------- Accounts receivable, net ....................... $ 112,864 $ 152,165 ========= ========= - ---------- (a) The decrease in allowance for uncollectable accounts is primarily due to the write off of Protection One customer accounts in 2001. On July 28, 2000, we entered into an asset-backed securitization agreement under which we periodically transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities." The agreement was renewed on July 26, 2001, and is annually renewable upon agreement by all parties. Under the terms of the agreement, we may transfer accounts receivable to the bankruptcy-remote SPE and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million (and upon request, subject to certain conditions, up to $175 million), in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned and consolidated. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE's receivables, including delinquency rates and debtor concentrations. We service the receivables transferred to the SPE and receive a servicing fee. These servicing fees are eliminated in consolidation. Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit resulting in an adjustment to the outstanding conduit interest. We record administrative expense on the undivided interest owned by the conduit, which was $5.4 million for the year ended 2001 and $3.7 million for the year ended December 31, 2000. These expenses are included in other income (expense) in our consolidated statements of income. The outstanding balance of SPE receivables was $43.3 million at December 31, 2001 and $85.5 million at December 31, 2000, which is net of an undivided interest of $100 million and $115.0 million in receivables sold by the SPE to the conduit. Our retained interest in the SPE's receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit's ownership interest in the SPE's receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit, and to absorb all credit losses incurred on any of the SPE's receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets. 76
5. FINANCIAL INSTRUMENTS The carrying values and estimated fair values of our financial instruments are as follows: Carrying Value Fair Value ------------------------ ------------------------ As of December 31, ---------------------------------------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- (In Thousands) Fixed-rate debt, net of current maturities (a) ... $2,418,838 $2,518,415 $2,229,998 $2,218,711 Other mandatorily redeemable securities (a) ...... 220,000 220,000 190,960 182,232 - ---------- (a) Fair value is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost, which approximates fair value and are not included in the table above. The fair value estimates presented herein are based on information available at December 31, 2001 and 2000. These fair value estimates have not been comprehensively revalued for the purpose of these consolidated financial statements since that date and current estimates of fair value may differ significantly from the amounts presented herein. Derivative Instruments and Hedge Accounting - ------------------------------------------- We use derivative financial instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, coal and electricity and changes in interest rates. We also use certain derivative instruments for trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power and fossil fuel markets. Derivative instruments used to manage commodity price risk inherent in fuel purchases and electricity sales are classified as energy trading contracts on our consolidated balance sheet. Energy trading contracts representing unrealized gain positions are reported as assets; energy trading contracts representing unrealized loss positions are reported as liabilities. Energy Trading Activities: We trade energy commodity contracts daily. Within the trading portfolio, we take certain positions to hedge physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We record most energy contracts, both physical and financial, at fair value. Changes in value are reflected in our consolidated statement of income. We use all forms of financial instruments, including futures, forwards, swaps and options. Each type of financial instrument involves different risks. We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in cash market prices and take advantage of selected market opportunities. We refer to these transactions as energy trading activities. Although we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio's value. To the extent we have an open position, we are exposed to fluctuating market prices that may adversely impact our financial position or results from operations. The prices we use to value price risk management activities reflect our best estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating 77
our position in an orderly manner over a reasonable period of time under present market conditions. We consider a number of risks and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counterparties and the time value of money. We continuously monitor the portfolio and value it daily based on present market conditions. Future changes in our creditworthiness and the creditworthiness of our counterparties may change the value of our portfolio. We adjust the value of contracts and set dollar limits with counterparties based on our assessment of their credit quality. Non-Trading Activities - Derivative Instruments and Hedging Activities: We use derivative financial instruments to reduce our exposure to adverse fluctuations in commodity prices, interest rates, and other market risks. When we enter into a financial instrument, we formally designate and document the instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transaction. Because of the high degree of correlation between the hedging instrument and the underlying exposure being hedged, fluctuations in the value of the derivative instruments are generally offset by changes in the value or cash flows of the underlying exposures being hedged. We record derivatives used for hedging commodity price risk in our consolidated balance sheets at fair value as energy trading contracts. The effective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is reported as a component of accumulated other comprehensive income (loss). This amount is reclassified into earnings in the period during which the hedged transaction affects earnings. Effectiveness is the degree to which gains and losses on the hedging instruments offset the gains and losses on the hedged item. The ineffective portion of the hedging relationship is recognized currently in earnings. The fair values of derivatives used to hedge or modify our risks fluctuate over time. These fair value amounts should not be viewed in isolation, but rather in relation to the fair values or cash flows of the underlying hedged transactions and the overall reduction in our risk relating to adverse fluctuations in interest rates, commodity prices and other market factors. In addition, the net income effect resulting from our derivative instruments is recorded in the same line item within our consolidated statements of income as the underlying exposure being hedged. We also formally assess, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposures. Any ineffective portion of a financial instrument's change in fair value is immediately recognized in net income. The notional volumes and terms of commodity contracts used for trading and non-trading purposes are as follows at December 31, 2001 and 2000: December 31, 2001 ----------------------------------------- Fixed Price Fixed Price Maximum Payor Receiver Term in Years ----------- ----------- ------------- Electricity (MWh's) ............... 3,942,352 2,976,504 4 Natural gas and oil (MMBtus) ...... 124,632,157 81,702,324 3 Coal (MMBtus) ...................... 245,667,419 237,819,001 3 December 31, 2000 ----------------------------------------- Fixed Price Fixed Price Maximum Payor Receiver Term in Years ----------- ----------- ------------- Electricity (MWh's) ............... 4,229,100 4,100,448 4 Natural gas and oil (MMBtus) ...... 113,030,679 80,754,417 3 Coal (MMBtus) ..................... -- -- -- 78
The following table presents the fair values of energy transactions by commodity at December 31, 2001 and 2000: Energy Trading Contract Energy Trading Contract Assets Liabilities ----------------------- ----------------------- 2001 2000 2001 2000 -------- -------- -------- -------- (In Thousands) Electricity $ 26,087 $108,726 $ 17,721 $104,337 Natural gas and oil 37,884 92,521 42,068 88,432 Coal 22,697 -- 24,570 -- -------- -------- -------- -------- Total $ 86,668 $201,247 $ 84,359 $192,769 ======== ======== ======== ======== During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are using futures and swap contracts with a total notional volume of 39,000,000 MMBtu and terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. Based on our best estimate of generating needs, we believe we have hedged 75% of our system requirements through this hedge. We have designated these hedging relationships as cash flow hedges in accordance with SFAS No. 133. Effective October 4, 2001, we entered into a $500 million interest rate swap agreement with a term of two years. The effect of the swap agreement is to fix the annual interest rate on the term loan at 6.18%. At December 31, 2001, the variable rate associated with this debt was 4.68%. This reduces our interest rate exposure due to variable rates. The swap is being accounted for as a cash flow hedge. The following table summarizes the effects our natural gas hedge and our interest rate swap had on our financial position and results of operations for 2001: Total Natural gas Interest Rate Cash Flow Hedge (a) Swap Hedges ----------- ------------- ---------- (Dollars in Thousands) Fair value of derivative instruments: Current ............................................... $ (9,988) $ -- $ (9,988) Long-term ............................................. (8,844) (2,656) (11,500) ---------- ---------- ---------- Total ............................................. $ (18,832) $ (2,656) $ (21,488) ========== ========== ========== Amounts in accumulated other comprehensive income .......... $ (29,079) $ (2,656) $ (31,735) Hedge ineffectiveness ...................................... 2,551 -- 2,551 Estimated income tax benefit ............................... 10,552 1,057 11,609 ---------- ---------- ---------- Net Comprehensive Loss ............................ $ (15,976) $ (1,599) $ (17,575) ========== ========== ========== Anticipated reclassifications to earnings during 2002 (b) .. $ 9,988 $ -- $ 9,988 Duration of hedge designation as of December 31, 2001 ...... 31 months 22 months -- - ---------- (a) Natural gas hedge liabilities are classified in the balance sheet as energy trading contracts. Gas prices have dropped since we entered into these hedging relationships. Due to the volatility of gas commodity prices, it is probable that gas prices will increase and decrease over the 31 months that these relationships are in place. (b) The actual amounts that will be reclassified to earnings could vary materially from this estimated amount due to changes in market conditions. 79
6. PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at December 31: 2001 2000 ---------- ---------- (In Thousands) Electric plant in service ........................ $6,289,316 $5,987,920 Less - Accumulated depreciation .................. 2,404,478 2,274,940 ---------- ---------- 3,884,838 3,712,980 Construction work in progress .................... 63,927 189,853 Nuclear fuel, net ................................ 33,883 30,791 ---------- ---------- Net utility plant ............................. 3,982,648 3,933,624 Non-utility plant in service ..................... 115,682 113,040 Less accumulated depreciation .................... 55,478 53,226 ---------- ---------- Net property, plant and equipment ............. $4,042,852 $3,993,438 ========== ========== Our depreciation expense on property, plant and equipment was $203.5 million in 2001, $201.7 million in 2000 and $186.1 million in 1999. 7. JOINT OWNERSHIP OF UTILITY PLANTS Our Ownership at December 31, 2001 -------------------------------------------------------------------------------- In-Service Accumulated Net Ownership Dates Investment Depreciation MW Percent ------------- ---------- ------------ ----- --------- (Dollars in Thousands) LaCygne 1.................... (a) June 1973 $ 188,277 $120,300 344.0 50 Jeffrey 1.................... (b) July 1978 306,136 148,000 625.0 84 Jeffrey 2.................... (b) May 1980 312,803 134,322 612.0 84 Jeffrey 3.................... (b) May 1983 411,582 179,867 623.0 84 Jeffrey wind 1............... (b) May 1999 874 98 0.6 84 Jeffrey wind 2............... (b) May 1999 873 97 0.6 84 Wolf Creek................... (c) Sept. 1985 1,387,391 528,268 550.0 47 State Line................... (d) June 2001 105,391 2,108 200.0 40 - ---------- (a) Jointly owned with Kansas City Power and Light Company (KCPL) (b) Jointly owned with Aquila, Inc. (c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc. (d) Jointly owned with Empire District Electric Company (EDE) Amounts and capacity presented above represent our share. Our share of operating expenses of the plants in service above, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in 1987, are included in operating expenses on our consolidated statements of income. Our share of other transactions associated with the plants is included in the appropriate classification in our consolidated financial statements. 80
8. INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD Our investments that are accounted for by the equity method are as follows: Ownership at Equity Earnings, December 31, Investment at December 31, Year Ended December 31, ------------ -------------------------- ----------------------- 2001 2001 2000 2001 2000 ------------ -------- -------- ------ ------ (Dollars in Thousands) ONEOK (a) ................................ 45% $598,929 $591,173 $4,721 $8,213 International companies and joint ventures(b) .......................... 9% to 50% 1,976 13,514 2,334 3,394 - ---------- (a) We also received approximately $40 million of preferred and common dividends in both 2001 and 2000. ONEOK equity earnings for 2001 decreased due to charges recorded for Enron Corp. exposure and for certain regulatory issues ONEOK has in Oklahoma. (b) Investment is aggregated. Individual investments are not material. During 2001, we disposed of our portfolio of affordable housing tax credit limited partnerships. We recorded earnings on these partnerships, including equity in earnings and loss on disposal, of $4.4 million. The following is summarized unaudited ONEOK financial information related to our investment in ONEOK: As of December 31, ------------------------------- 2001 2000 ---------- ---------- (In Thousands) Balance Sheet: Current assets ................................... $1,561,969 $3,324,959 Non-current assets ............................... 4,317,190 4,035,386 Current liabilities .............................. 1,818,417 3,526,561 Long-term debt, net .............................. 1,498,012 1,336,082 Other deferred credits and other liabilities ..... 1,297,440 1,272,745 Equity ........................................... 1,265,290 1,224,957 For the Year Ended December 31, ------------------------------- 2001 2000 ---------- ---------- (In Thousands) Income Statement: Revenues ......................................... $6,803,146 $6,642,858 Gross profit ..................................... 908,785 797,132 Income before cumulative effect of a change in accounting principle .......................... 103,716 143,492 Net income ....................................... 101,565 145,607 At December 31, 2001, our ownership interest in ONEOK was comprised of approximately 4.7 million common shares and approximately 19.9 million convertible preferred shares, each share of which is convertible into two shares of ONEOK common stock. If all the preferred shares were converted, we would then own approximately 45% of ONEOK's common shares outstanding. ONEOK earnings for 2001 include a pretax charge of $34.6 million for unrecovered gas costs from the winter of 2000/2001 and a $37.4 million pretax charge related to the Enron Corp. bankruptcy. The charge for the outstanding gas costs is a result of the Oklahoma Corporation Commission order denying ONEOK the right to collect a portion of gas costs incurred during the winter of 2000/2001. Gas prices increased significantly in this period due to high demand and a perceived supply shortage. The charges related to Enron Corp.'s bankruptcy are due to Enron Corp.'s non-payment of both financial and physical natural gas positions for November and December of 2001. These charges also include the value of forward natural gas positions on ONEOK's termination of natural 81
gas contracts in early January 2002. These contracts were related to physical commodity sales and storage management activities. 9. MONITORED SERVICES' CUSTOMER ACCOUNTS The following is a rollforward of the investment in customer accounts (at cost) of the monitored services segment for the following years: December 31, ------------------------------ 2001 2000 ----------- ----------- (In Thousands) Beginning customer accounts, net ......... $ 1,005,505 $ 1,122,585 Acquisition of customer accounts ......... 17,482 54,993 Amortization of customer accounts ........ (153,019) (163,297) Sale of accounts ......................... (42,246) -- Purchase holdbacks and other ............. 2,986 (8,776) ----------- ----------- Ending customer accounts, net ....... $ 830,708 $ 1,005,505 =========== =========== Accumulated amortization of the investment in customer accounts at December 31, 2001 was $630.5 million and $493.4 million at December 31, 2000. Customer account amortization expense was $153.0 million for 2001, $163.3 million for 2000, and $186.0 million for 1999. During 2001, the monitored services segment's attrition, along with its change in focus from growth to strengthening operations, dispositions of certain accounts and Protection One's conversion to MAS(R), resulted in a net loss of 267,347 customers or a 17.8% decrease in its customer base from January 1, 2001. This was the primary cause of Protection One's $59.9 million decline in monitoring and related service revenues in its North America segment from January 1, 2001. Protection One expects this trend will continue until the efforts it is making to acquire new accounts and reduce its rate of attrition become more successful than they have been to date. Until Protection One is able to reverse this trend, net losses of customer accounts will materially and adversely affect our business, financial position and results of operations. 10. SHORT-TERM DEBT We have an arrangement with certain banks to provide a revolving credit facility on a committed basis totaling $500 million. The facility is secured by our and KGE's first mortgage bonds and matures on March 17, 2003. We also have arrangements with certain banks to provide unsecured short-term lines of credit on a committed basis totaling approximately $7.0 million. As of December 31, 2001, borrowings on these facilities were $222.3 million. The agreements provide us with the ability to borrow at different market-based interest rates. We pay commitment or facility fees in support of these lines of credit. Under the terms of the agreements, we are required, among other restrictions, to maintain a total debt to total capitalization ratio of not greater than 65% at all times. We are in compliance with this covenant. At December 31, 2001, the capitalization ratio was 61.4%. Under the terms of the facility, the impairment charge to be recorded in the first quarter of 2002 will not affect compliance with this covenant in future periods. 82
Information regarding our short-term borrowings is as follows: As of December 31, ---------------------- 2001 2000 -------- -------- (Dollars in Thousands) Borrowings outstanding at year end: Credit agreement ..................................................... $222,300 $ 35,000 Weighted average interest rate on debt outstanding at year end ............ 3.44% 8.11% Weighted average short-term debt outstanding during the year .............. $123,131 $402,845 Weighted daily average interest rates during the year, including fees ..... 6.58% 7.92% Our interest expense on short-term debt and other was $40.6 million in 2001, $63.1 million in 2000 and $57.7 million in 1999. 83
11. LONG-TERM DEBT Long-term debt outstanding is as follows at December 31: 2001 2000 ---------- ---------- (In Thousands) Western Resources - ----------------- First mortgage bond series: 7 1/4% due 2002 ........................................................ $ 100,000 $ 100,000 8 1/2% due 2022 ........................................................ 125,000 125,000 7.65% due 2023 ......................................................... 100,000 100,000 ---------- ---------- 325,000 325,000 ---------- ---------- Pollution control bond series: Variable due 2032, 1.43% at December 31, 2001 .......................... 45,000 45,000 Variable due 2032, 1.70% at December 31, 2001 .......................... 30,500 30,500 6% due 2033 ............................................................ 58,340 58,410 ---------- ---------- 133,840 133,910 ---------- ---------- 6 7/8% unsecured senior notes due 2004 ...................................... 355,560 370,000 7 1/8% unsecured senior notes due 2009 ...................................... 150,000 150,000 6.80% unsecured senior notes due 2018 ....................................... 28,104 28,977 6.25% unsecured senior notes due 2018, putable/callable 2003 ................ 384,300 400,000 Senior secured term loan due 2003, variable rate of 7.9% at December 31, 2001 .................................................................... 591,000 600,000 Other long-term agreements .................................................. 5,830 16,889 ---------- ---------- 1,514,794 1,565,866 ---------- ---------- KGE - --- First mortgage bond series: 7.60% due 2003 ......................................................... 135,000 135,000 6 1/2% due 2005 ........................................................ 65,000 65,000 6.20% due 2006 ......................................................... 100,000 100,000 ---------- ---------- 300,000 300,000 ---------- ---------- Pollution control bond series: 5.10% due 2023 ......................................................... 13,493 13,623 Variable due 2027, 1.35% at December 31, 2001 .......................... 21,940 21,940 7.0% due 2031 .......................................................... 327,500 327,500 Variable due 2032, 1.5% at December 31, 2001 ........................... 14,500 14,500 Variable due 2032, 1.53% at December 31, 2001 .......................... 10,000 10,000 ---------- ---------- 387,433 387,563 ---------- ---------- Protection One - -------------- Convertible senior subordinated notes due 2003, fixed rate 6.75% ............ 23,770 23,785 Senior subordinated discount notes due 2005, effective rate 11.8% ........... 33,520 42,887 Senior unsecured notes due 2005, fixed rate 7.375% .......................... 203,650 204,650 Senior subordinated notes due 2009, fixed rate 8.125% ....................... 174,840 255,740 Other ....................................................................... 898 267 ---------- ---------- 436,678 527,329 ---------- ---------- Protection One Europe - --------------------- CET recourse financing agreements, average effective rate 13.17%(a) .......... 34,931 33,512 ---------- ---------- Unamortized debt premium (b) ................................................... 12,837 13,541 Less: Unamortized debt discount (b) ............................................... 6,555 7,047 Long-term debt due within one year .......................................... 160,576 41,825 ---------- ---------- Long-term debt, net .................................................... $2,978,382 $3,237,849 ========== ========== - ---------- (a) Agreements mature on various dates not exceeding four years. (b) Debt premiums, discounts and expenses are being amortized over the remaining lives of each issue. The amount of our first mortgage bonds authorized by our 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 84
Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion, unless amended. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions of each mortgage. Our unsecured debt represents general obligations that are not secured by any of our properties or assets. Any unsecured debt will be subordinated to all of our secured debt, including the first mortgage bonds. The notes are structurally subordinated to all secured and unsecured debt of our subsidiaries. We have material amounts of debt maturing over the next one to two years (see also Note 10 above). This debt will need to be refinanced. We are evaluating strategies for refinancing this debt. On June 28, 2000, we entered into a $600 million, multi-year term loan that replaced two revolving credit facilities that matured on June 30, 2000. We had $591 million outstanding on the term loan at December 31, 2001. The term loan is secured by our and KGE's first mortgage bonds and has a maturity date of March 17, 2003. The term loan agreement contains requirements for maintaining certain consolidated leverage ratios, interest coverage ratios and consolidated debt to capital ratios. At December 31, 2001, we were in compliance with all of these requirements. In January 2002, we repaid $44 million of the term loan with the proceeds of our sale of investments in low income housing tax credit partnerships. The outstanding balance of the term loan after this prepayment was $547 million. In March 2002, we entered into an amendment to the term loan that adds to the calculation of consolidated earnings before interest, taxes, depreciation and amortization, the severance costs incurred in the fourth quarter of 2001 and the first quarter of 2002 related to our work force reductions, and maintains the current maximum consolidated leverage ratio of 5.75 to 1.0 through the maturity date of the term loan in March 2003. We expect to be in compliance with all covenants through the remaining term of this agreement. Maturities of the term loan through March 17, 2003, are as follows: Principal Amount ---------------- Year (In Thousands) ---- 2002 ....................... $ 6,000 2003 ....................... 541,000 -------- $547,000 ======== Interest on the term loan is payable on the expiration date of each borrowing under the facility or quarterly if the term of the borrowing is greater than three months. The weighted average interest rate, including amortization of fees, on the term loan for the year ending December 31, 2001, was 7.9%. Maturities of long-term debt as of December 31, 2001 are as follows: Principal Amount ---------------- As of December 31, (In Thousands) ------------------ 2002 (a).................... $ 160,576 2003........................ 715,414 2004........................ 364,128 2005........................ 306,414 2006........................ 100,457 Thereafter.................. 1,491,969 ---------- $3,138,958 ========== - ---------- (a) Amount due includes $38.5 million related to the sale of investments required to be repaid under the mandatory prepayment provisions of our credit agreement. Our interest expense on long-term debt was $227.6 million in 2001, $226.4 million in 2000 and $236.4 million in 1999. 85
In 1998, Protection One issued $350 million of unsecured Senior Subordinated Notes due 2009. As a result of the completion of a registered offer to exchange a new series of 8.125% Series B Senior Subordinated Notes for a like amount of Protection One's outstanding 8.125% Senior Subordinated Notes, effective June 1, 2001 the annual interest rate on all of such outstanding notes decreased from 8.625% to 8.125%. Because the exchange offer was not completed within six months of the issuance date, Protection One had been paying an additional 0.5% interest penalty since June 1999. At the time of the exchange, the resulting annual interest savings were $1.2 million. The notes are redeemable at Protection One's option, in whole or in part, at a predefined price. Interest on these notes 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 13.625%. 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. As of June 30, 2000, the notes became redeemable at Protection One's option, at a specified redemption 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. As of September 19, 1999, the notes became redeemable, at Protection One's option, at a specified redemption price. During the last three years, Protection One and our bonds were repurchased in the open market and extraordinary gains were recognized on the retirement of these bonds of $23.2 million in 2001, $49.2 million in 2000 and $13.4 million in 1999, net of tax. From January 1, 2002 through February 2002, a gain of $3.6 million, net of tax, was recognized on the repurchase of Protection One and our bonds. Protection One Europe 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. 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. At December 31, 2001, Protection One was in compliance with its debt covenants. The indentures governing all of Protection One's debt securities require that Protection One offer to repurchase the securities in certain circumstances following a change of control. 12. EMPLOYEE BENEFIT PLANS Pension - ------- We maintain 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. Our 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. We also maintain a non-qualified Executive Salary Continuation Program for the benefit of certain management employees, including executive officers. 86
Post-retirement Benefits - ------------------------ We accrue the cost of post-retirement benefits, primarily medical benefit costs, during the years an employee provides service. The following tables summarize the status of our pension and other postretirement benefit plans: Pension Benefits Post-retirement Benefits ----------------------- ------------------------ December 31, 2001 2000 2001 2000 - ---------------------------------------------------------------------------------------------------------------------- (In Thousands) Change in Benefit Obligation: Benefit obligation, beginning of year ....................... $ 383,403 $ 350,749 $ 102,530 $ 79,287 Service cost ................................................ 9,042 7,964 1,477 1,344 Interest cost ............................................... 28,783 26,901 7,344 7,158 Plan participants' contributions ............................ -- -- 1,189 1,130 Benefits paid ............................................... (23,982) (20,337) (7,741) (6,476) Assumption changes .......................................... 39 19,350 587 5,038 Actuarial losses (gains) .................................... 21,662 (2,491) 2,697 15,049 Curtailments, settlements and special term benefits ......... 4,867 1,267 547 -- --------- --------- --------- --------- Benefit obligation, end of year ............................. $ 423,814 $ 383,403 $ 108,630 $ 102,530 ========= ========= ========= ========= Change in Plan Assets: Fair value of plan assets, beginning of year ................ $ 490,173 $ 506,995 $ 394 $ 261 Actual return on plan assets ................................ (2,144) 1,448 19 17 Employer contribution ....................................... 3,015 2,067 6,716 5,462 Plan participants' contributions ............................ -- -- 1,189 1,130 Benefits paid ............................................... (23,982) (20,337) (7,741) (6,476) --------- --------- --------- --------- Fair value of plan assets, end of year ...................... $ 467,062 $ 490,173 $ 577 $ 394 ========= ========= ========= ========= Funded status ............................................... $ 43,248 $ 106,770 $(108,053) $(102,136) Unrecognized net (gain)/loss ................................ (65,477) (141,443) 14,447 11,904 Unrecognized transition obligation, net ..................... 141 174 44,195 48,183 Unrecognized prior service cost ............................. 24,071 29,538 (2,797) (3,264) --------- --------- --------- --------- Prepaid (accrued) postretirement benefit costs .............. $ 1,983 $ (4,961) $ (52,208) $ (45,313) ========= ========= ========= ========= Amounts recognized in the statement of financial position consist of: Prepaid benefit cost ........................................ $ 19,687 $ 9,712 $ N/A $ N/A Accrued benefit liability ................................... (17,704) (14,673) (52,208) (45,313) Additional minimum liability ................................ (7,370) -- N/A N/A Intangible asset ............................................ 658 -- N/A N/A Accumulated other comprehensive income ...................... 6,712 -- N/A N/A --------- --------- --------- --------- Net amount recognized ....................................... $ 1,983 $ (4,961) $ (52,208) $ (45,313) ========= ========= ========= ========= Actuarial Assumptions: Discount rate ............................................... 7.25% 7.25-7.75% 7.25% 7.25-7.75% Expected rate of return ..................................... 9.0-9.25% 9.00-9.25% 9.0-9.25% 9.00-9.25% Compensation increase rate .................................. 4.0-5.0% 4.25-5.00% 4.0-5.0% 4.50-5.00% Components of net periodic (benefit) cost: Service cost ................................................ $ 9,042 $ 7,972 $ 1,477 $ 1,344 Interest cost ............................................... 28,783 26,977 7,344 7,157 Expected return on plan assets .............................. (43,001) (39,143) (36) (24) Amortization of unrecognized transition obligation, net ..... 34 35 3,987 3,988 Amortization of unrecognized prior service costs ............ 3,317 3,316 (466) (466) Amortization of (gain)/loss, net ............................ (8,327) (9,427) 794 457 Other ....................................................... -- 9 -- -- Curtailments, settlements and special term benefits ......... 6,133 -- -- -- --------- --------- --------- --------- Net periodic (benefit) cost ................................. $ (4,019) $ (10,261) $ 13,100 $ 12,456 ========= ========= ========= ========= For measurement purposes, an annual health care cost growth rate of 5.25%-6.0% was assumed for 2001. The health care cost trend rate has a significant effect on the projected benefit obligation. Increasing the trend rate 87
by 1% each year would increase the present value of the accumulated projected benefit obligation by $2.5 million and the aggregate of the service and interest cost components by $0.2 million. A 1% decrease in the trend rate would decrease the present value of the accumulated projected benefit obligation by $2.4 million and the aggregate of the service and interest cost components by $0.2 million. Savings Plans - ------------- We maintain savings plans in which substantially all employees participate, with the exception of Protection One and Protection One Europe employees. We match employees' contributions with Western Resources' stock up to specified maximum limits. Our contributions to the plans are deposited with a trustee and are invested in one or more funds, including the company stock fund. Our contributions were $4.4 million for 2001, $3.9 million for 2000 and $3.7 million for 1999. In 1999, we established a qualified employee stock purchase plan, the terms of which allow full-time non-union employees to participate in the purchase of designated shares of our common stock at no more than a 15% discounted price. Our employees purchased 67,519 shares in 2001, pursuant to this plan, at an average price per share of $14.55625. In 2000, employees purchased 249,050 shares at an average price per share of $13.9984. A total of 1,250,000 shares of common stock have been reserved for issuance under this program. Protection One also maintains a savings plan. Contributions, made at Protection One's election, are allocated among participants based upon the respective contributions made by the participants through salary reductions during the year. Protection One's matching contributions may be made in Protection One common stock, in cash or in a combination of both stock and cash. Protection One's matching cash contribution to the plan was approximately $1.1 million for 2001, $0.7 million for 2000 and $0.9 million for 1999. Protection One maintains a qualified employee stock purchase plan that allows eligible employees to acquire shares of Protection One common stock at periodic intervals through their accumulated payroll deductions. A total of 1,650,000 shares of common stock have been reserved for issuance in this program and a total of 912,186 shares have been issued including the issuance of 489,791 shares in January 2002. Stock Based Compensation Plans - ------------------------------ We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which utility employees are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and board members (Plan Participants). Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, restricted shares, restricted share units (RSUs), performance shares and performance share units to Plan Participants. Up to five million shares of common stock may be granted under the LTISA Plan. During 2001, 579,915 RSUs were granted to a broad-based group of over 1,000 non-union employees. Each RSU represents a right to receive one share of our common stock at the end of the restricted period assuming performance criteria are met. During 2000, 710,352 RSUs were granted. Also in 2000, non-union employees were offered the opportunity to exchange their stock options for RSUs of approximately equal economic value. As a result, 2,246,865 stock options were canceled in 2000 in exchange for 614,741 RSUs. We granted a total of 152,000 restricted shares in 1999. The grant of restricted stock is shown as a separate component of shareholders' equity. Unearned compensation is being amortized to expense over the vesting period. This compensation expense is shown as a separate component of shareholders' equity. Another component of the LTISA Plan is the Executive Stock for Compensation program where in the past eligible employees were entitled to receive RSUs in lieu of cash compensation at the end of a deferral period. The Executive Stock for Compensation program was modified in 2001 to pay a portion of current compensation in the form of stock. In 2001, eligible employees were issued 31,881 shares of common stock representing $0.7 million of compensation. In 2000, 95,000 RSUs were awarded in lieu of $1.3 million in cash compensation. In 1999, 35,000 88
RSUs were awarded in lieu of $0.7 million of cash compensation. Dividend equivalents accrue on the awarded RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on our common stock. Stock options and RSUs under the LTISA plan are as follows: As of December 31, 2001 2000 1999 ------------------------ ------------------------ ------------------------ Weighted- Weighted- Weighted- Average Average Average Shares Exercise Shares Exercise Shares Exercise (Thousands) Price (Thousands) Price (Thousands) Price ---------- ---------- ---------- ---------- ---------- ---------- Outstanding, beginning of year ...... 2,105.6 $ 22.583 2,418.6 $ 34.139 1,590.7 $ 36.106 Granted ............................. 649.4 24.75 1,953.1 15.513 981.6 30.613 Exercised ........................... (278.2) 19.05 (0.5) 15.625 -- -- Forfeited ........................... (21.7) 17.86 (2,265.6) 28.827 (153.7) 31.985 ---------- ---------- ---------- Outstanding, end of year ............ 2,455.1 $ 24.56 2,105.6 $ 22.583 2,418.6 $ 34.139 ========== ========== ========== Weighted-average fair value of awards granted during the year .......... $ 24.08 $ 11.28 $ 8.22 Stock options and RSUs issued and outstanding at December 31, 2001 are as follows: Number Weighted- Weighted- Range of Issued Average Average Exercise and Contractual Exercise Price Outstanding Life in Years Price --------------- ----------- ------------- --------- Options - Exercisable: 2000............................ $ 15.3125 3,494 9 $ 15.31 1999............................ 27.8125-32.125 28,546 8 29.44 1998............................ 38.625-43.125 218,380 7 40.97 1997............................ 30.750 185,630 6 30.75 1996............................ 29.250 90,290 5 29.25 ----------- 526,340 ----------- Options - Not Exercisable: 2000............................ $ 15.3125 14,273 9 $ 15.31 1999............................ 27.8125-32.125 11,660 8 29.44 ----------- 25,933 ----------- Range of Fair Value at Grant Date --------------- Restricted share units: 2001............................ $21.600-$24.200 576,470 2000............................ 15.3125-19.875 1,037,893 1999............................ 27.8125-32.125 152,000 1998............................ 38.625 136,500 ----------- 1,902,863 ----------- Total issued................. 2,455,136 =========== An equal number of dividend equivalents were issued to recipients of stock options and RSUs. Recipients of RSUs receive dividend equivalents when dividends are paid on shares of company stock. The value of each dividend equivalent related to stock options is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend equivalents, with respect to stock options, expire after nine years from date of grant. The weighted-average grant-date fair value of the dividend equivalents on stock options was $6.28 in 2001 and $6.27 in 2000. 89
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, 2000. There were no options granted in 2001. 2000 ---- Dividend yield................................. 6.32% Expected stock price volatility................ 16.42% Risk-free interest rate........................ 5.79% Remaining expected option life................. 5 years Protection One Stock Warrants and Options - ----------------------------------------- Protection One has outstanding stock warrants and options that were considered reissued and exercisable upon our 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 of Protection One 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. Options issued since 1997 have a term of 10 years and vest ratably over 3 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 common stock from December 31, 1999 through December 31, 2001 is as follows: December 31, ------------------------------------------------------------------- 2001 2000 1999 --------------------- --------------------- --------------------- Weighted- Weighted- Weighted- Average Average Average Shares Exercise Shares Exercise Shares Exercise (Thousands) Price (Thousands) Price (Thousands) Price ----------- -------- ----------- -------- ----------- -------- Outstanding, beginning of year .... 4,404.6 $ 6.058 3,788.1 $ 7.232 3,422.7 $ 7.494 Granted ........................... 1,880.5 1.327 922.5 1.436 1,092.9 7.905 Exercised ......................... (59.7) 2.490 (5.4) 3.890 -- -- Forfeited ......................... (555.3) 4.941 (300.6) 6.698 (727.5) 10.125 -------- -------- -------- Outstanding, end of year .......... 5,670.1 4.281 4,404.6 6.058 3,788.1 7.232 ======== ======== ======== 90
Stock options and warrants of Protection One issued and outstanding at December 31, 2001 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 - $6.500 130,800 3 $6.4954 Fiscal 1996................ 8.000 - 15.000 438,400 4 10.0478 Fiscal 1997................ 9.500 - 15.000 209,000 5 11.9565 Fiscal 1998................ 11.000 812,500 6 11.0000 Fiscal 1999................ 5.250 - 8.9275 355,606 7 8.4857 Fiscal 2000................ 1.4375 153,372 8 1.4375 1993 Warrants.............. 0.167 428,400 2 0.1670 1995 Note Warrants......... 3.890 780,837 3 3.8900 ----------- Total................ 3,308,915 ----------- Not Exercisable: 1999 options............... $5.2500 - $8.9275 165,008 7 $8.4857 2000 options............... 1.4375 315,648 8 1.4375 2001 options............... 0.8750 - 1.480 1,880,541 9 1.3273 ----------- Total................ 2,361,197 ----------- Total outstanding............. 5,670,112 =========== The weighted average fair value of options for Protection One stock granted by Protection One during 2001, 2000 and 1999 estimated on the date of grant were $1.88, $1.13 and $5.41. The fair value was calculated using the following assumptions: Year Ended December 31, -------------------------------- 2001 2000 1999 ------- ------- ------- Expected stock price volatility............. 83.92% 92.97% 64.06% Risk free interest rate..................... 4.95% 4.87% 6.76% Expected option life........................ 7 years 6 years 6 years Effect of Stock-Based Compensation on Earnings Per Share We account for both our 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 SFAS No. 123, "Accounting for Stock-Based Compensation," we would have recognized additional compensation costs during 2001, 2000 and 1999 as shown in the table below. Year Ended December 31, 2001 2000 1999 - ------------------------------------------------------------------------------------------------------- (In Thousands, Except Per Share Amounts) Earnings (loss) available for common stock (a): As reported ............................................. $ (21,771) $ 135,352 $ 13,167 Pro forma ............................................... (21,259) 134,274 10,699 Basic and diluted earnings (losses) per common share (a): As reported ............................................. $ (0.31) $ 1.96 $ 0.20 Pro forma ............................................... $ (0.30) 1.95 0.16 - ---------- (a) Represents consolidated Western Resources. 91
Split Dollar Life Insurance Program - ----------------------------------- We have established a split dollar life insurance program for our benefit and the benefit of certain of our executives. Under the program, we have 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 us. We retain 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 us 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 $18.6 million as of December 31, 2001 and $19.1 million as of December 31, 2000. The obligations under this program can increase and decrease based on our total return to shareholders and payments to plan participants. This liability decreased approximately $0.5 million in 2001 primarily due to balance adjustments and $12.8 million in 2000 due primarily to payments to plan participants. In 1999, the liability decreased approximately $10.5 million based on our total return to shareholders. Under current tax rules, payments to active employees in exchange for their interest in the death benefits may not be fully deductible by us for income tax purposes. Subsequent to December 31, 2001, this liability was reduced by a payment of $4.6 million pursuant to the plan. 13. INCOME TAXES Income tax expense (benefit) is composed of the following components at December 31: 2001 2000 1999 -------- -------- -------- (In Thousands) Current income taxes: Federal ............................... $(21,942) $ 39,747 $ 12,996 State ................................. (186) 10,131 9,622 Deferred income taxes: Federal ............................... (28,363) 18,060 (35,857) State ................................. 1,180 9,585 (6,582) Investment tax credit amortization ...... (6,646) (6,045) (6,054) -------- -------- -------- Total ............................ (55,957) 71,478 (25,875) Less taxes classified in: Extraordinary gain .................... 12,571 26,514 6,322 Cumulative effect of accounting change 12,347 (1,097) -- -------- -------- -------- Total income tax (benefit) expense .... $(80,875) $ 46,061 $(32,197) ======== ======== ======== 92
Under SFAS No. 109, "Accounting for Income Taxes," temporary differences gave rise to deferred tax assets and deferred tax liabilities summarized in the following table. December 31, -------------------------- 2001 2000 ---------- ---------- (In Thousands) Deferred tax assets: Deferred gain on sale-leaseback ............. $ 76,806 $ 82,013 Customer accounts ........................... 60,023 49,853 General business credit carryforward (a) .... 28,494 11,012 Accrued liabilities ......................... 23,511 21,108 Disallowed plant costs ...................... 16,650 17,758 Long-term energy contracts .................. 13,538 14,209 Other ....................................... 115,874 110,261 ---------- ---------- Total deferred tax assets ................ $ 334,896 $ 306,214 ========== ========== Deferred tax liabilities Accelerated depreciation .................... $ 617,682 $ 627,024 Acquisition premium ......................... 267,161 275,159 Deferred future income taxes ................ 222,071 188,006 Investment tax credits ...................... 84,900 91,546 Other ....................................... 39,443 44,562 ---------- ---------- Total deferred tax liabilities ........... $1,231,257 $1,226,297 ========== ========== - ---------- (a) Balance represents unutilized tax credits generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These credits expire beginning 2019 through 2021. Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows: December 31, ----------------------- 2001 2000 -------- -------- (In Thousands) Current deferred tax assets, net ................. $ 27,817 $ 34,512 Non-current deferred tax liabilities, net ........ 924,178 954,595 -------- -------- Net deferred tax liabilities ..................... $896,361 $920,083 ======== ======== In accordance with various rate orders, we have not yet collected through rates certain accelerated tax deductions, which have been passed on to customers. We believe it is probable that the net future increases in income taxes payable will be recovered from customers. We have recorded a regulatory asset for these amounts. These assets are also a temporary difference for which deferred income tax liabilities have been provided. This liability is classified above as deferred future income taxes. 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: For the Year Ended December 31, ------------------------------ 2001 2000 1999 ------ ------ ------ Effective income tax rate .................................. (56.3)% 33.6% (108.6)% Effect of: State income taxes ...................................... 0.6 (9.4) (7.1) Amortization of investment tax credits .................. 4.6 4.4 20.4 Corporate-owned life insurance policies ................. 9.5 8.4 28.0 Affordable housing tax credits .......................... 6.8 7.8 31.3 Accelerated depreciation flow through and amortization .. (0.1) (4.9) (12.2) Dividends received deduction ............................ 7.1 7.1 34.3 Amortization of goodwill ................................ (10.6) (13.0) (19.3) Other ................................................... 3.4 1.0 (1.8) ------ ------ ------ Statutory federal income tax rate .......................... (35.0)% 35.0% (35.0)% ====== ====== ====== 14. COMMITMENTS AND CONTINGENCIES Municipalization Efforts by Wichita - ----------------------------------- In December 1999, the City Council of Wichita, Kansas, authorized the hiring of an outside consultant to determine the feasibility of creating a municipal electric utility to replace KGE as the supplier of electricity in Wichita. The feasibility study was released in February 2001 and estimates that the City of Wichita would be required to pay us $145 million for our stranded costs if it were to municipalize. However, we estimate the amount to be substantially greater. In order to municipalize KGE's Wichita electric facilities, the City of Wichita would be required to purchase KGE's facilities or build a separate independent system and arrange for its own power supply. These costs are in addition to the stranded costs for which the city would be required to reimburse us. On February 2, 2001, the City of Wichita announced its intention to proceed with its attempt to municipalize KGE's retail electric utility business in Wichita. KGE will oppose municipalization efforts by the City of Wichita. Should the city be successful in its municipalization efforts without providing us adequate compensation for our assets and lost revenues, the adverse effect on our business and financial condition could be material. KGE's franchise with the City of Wichita to provide retail electric service is effective through December 1, 2002. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, KGE will continue to have the right to serve the customers in Wichita following the expiration of the franchise, assuming the system is not municipalized. Customers within the Wichita metropolitan area account for approximately 23% of our total energy sales. Purchase Orders and Contracts - ----------------------------- As part of our ongoing operations and construction program, we have commitments under purchase orders and contracts, excluding fuel (which is discussed below under "-- Fuel Commitments,") that have an unexpended balance of approximately $98.4 million at December 31, 2001. Manufactured Gas Sites - ---------------------- We have been associated with 15 former manufactured gas sites located in Kansas that may contain coal tar and other potentially harmful materials. We and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement governing all future work at these sites. The terms of the consent agreement will allow us to investigate these sites and set remediation priorities based on the results of the investigations and risk analysis. At December 31, 2001, the costs incurred for preliminary site investigation and risk assessment have been 94
minimal. In accordance with the terms of the strategic alliance with ONEOK, ownership of twelve of these sites and the responsibility for clean-up of these sites were transferred to ONEOK. The ONEOK agreement limits our future liability associated with these sites to an immaterial amount. Our investment earnings from ONEOK could be impacted by these costs. Superfund Sites - --------------- In December 1999, we were identified as one of more than 1,000 potentially responsible parties at an EPA Superfund site in Kansas City, Kansas (Kansas City site). We have previously been associated with other Superfund sites for which our liability has been classified as de minimis, or insignificant, and any potential obligations have been settled at minimal cost. Since 1993, we have settled Superfund obligations at three sites for a total of $141,300. We were notified in 2001 that one site was issued an EPA "Notice of Completion of Work" and final oversight costs have been paid out of the existing joint responsible party account, which has an adequate balance to cover this expense. This effectively closes this site and we can expect a refund in 2002 of our share of the remaining funds in this account. Our obligation, if any, at the Kansas City site is expected to be limited based upon previous experience and the limited nature of our business transactions with the previous owners of the site. In the opinion of our management, the resolution of this matter is not expected to have a material impact on our financial position or results of operations. Clean Air Act - ------------- We must comply with the provisions of The Clean Air Act Amendments of 1990 that require a two-phase reduction in certain emissions. We have installed continuous monitoring and reporting equipment to meet the acid rain requirements. Material capital expenditures have not been required to meet Phase II sulfur dioxide and nitrogen oxide requirements. Nuclear Decommissioning - ----------------------- We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund. On September 1, 1999, Wolf Creek submitted the 1999 Decommissioning Cost Study to the KCC for approval. The KCC approved the 1999 Decommissioning Cost Study on April 26, 2000. Based on the study, our share of Wolf Creek's decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $631 million during the period 2025 through 2034, or approximately $221 million in 1999 dollars. These costs include decontamination, dismantling and site restoration and were calculated using an assumed inflation rate of 3.6% over the remaining service life from 1999 of 26 years. The actual decommissioning costs may vary from the estimates because of changes in the assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment. On May 26, 2000, we filed an application with the KCC requesting approval of the funding of our decommissioning trust on this basis. Approval was granted by the KCC on September 20, 2000. Decommissioning costs are currently being charged to operating expense in accordance with prior KCC orders. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek. Amounts expensed approximated $4.0 million in 2001 and will increase annually to $5.5 million in 2024. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.8%. Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $66.6 million at December 31, 2001 and $64.2 million at December 31, 2000. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability. 95
Storage of Spent Nuclear Fuel - ----------------------------- Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee of one-tenth of a cent for each kilowatt-hour of net nuclear generation produced for the future disposal of spent nuclear fuel. These disposal costs are charged to cost of sales. A permanent disposal site will not be available for the nuclear industry until 2010 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2016. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025. Asset Retirement Obligations - ---------------------------- In August 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When it is initially recorded, we will capitalize the estimated asset retirement obligation by increasing the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the capitalized cost will be depreciated over the life of the asset. The standard is effective for fiscal years beginning after June 15, 2002. We expect to adopt this standard January 1, 2003. This standard will impact the way we currently account for the decommissioning of Wolf Creek. In addition to the accounting for the Wolf Creek decommissioning, we are also reviewing what impact this pronouncement will have on our current accounting practices and our results of operations as it relates to other asset retirement obligations we may identify. The impact is unknown at this time. Nuclear Insurance - ----------------- The Price-Anderson Act, originally passed by Congress in 1957 and most recently amended in 1988, requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $200 million. If this amount is not sufficient to cover claims arising from an accident, the second level - Secondary Financial Protection - applies. For the second level, each licensed nuclear unit must pay a retroactive premium equal to its proportionate share of the excess loss, up to a maximum of $88.1 million per unit per accident. Currently, 106 nuclear units are participating in the Secondary Financial Protection program - 103 operating units and three closed units that still handle used nuclear fuel. The number of units participating in the program will be reduced as decommissioned units apply for and receive exemptions. Nuclear power plants provide a total of $9.5 billion in insurance coverage to compensate the public in the event of a nuclear accident. Taxpayers and the federal government pay nothing for this coverage. The Nuclear Regulatory Commission (NRC) was required to submit a report to Congress, which was submitted in September 1998 and describes the benefits that the act provides to the public. It also recommends that the act be extended for an additional ten years. The DOE submitted a report to Congress in March 1999, recommending renewal of the act. Bipartisan legislation was introduced in the 106th Congress in the Senate providing a simple renewal of Price-Anderson based on the DOE and NRC reports. The nuclear industry supports such a legislative approach for consideration early in the 107th Congress. 96
Unless Congress renews the Price-Anderson Act, it will expire in part on August 1, 2002 as follows: . The only part of Price-Anderson that expires on August 1, 2002, is the authority of the NRC and the DOE to enter into new indemnity agreements after that date. Existing indemnity agreements would continue in full force and effect. . Without renewal, new nuclear power plants could not be covered, nor could new DOE contracts have the indemnity provision (including the proposed high-level radioactive waste disposal site in Yucca Mountain, Nevada). The Price-Anderson Act limits the combined public liability of the owners of nuclear power plants to $9.5 billion for a single nuclear incident. If this liability limitation is insufficient, the United States Congress will consider taking whatever action is necessary to compensate the public for valid claims. However, on February 2, 2002, the United States Senate announced that it is considering discontinuing the federal insurance provision. The Wolf Creek owners have purchased the maximum available private insurance of $200 million. The remaining balance is provided by an assessment plan mandated by the NRC. Under this plan, the owners are jointly and severally subject to a retrospective assessment of up to $88.1 million in the event there is a major nuclear incident involving any of the nation's licensed reactors. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. There is a limitation of $10 million in retrospective assessments per incident, per year. The owners carry decontamination liability, premature decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion ($1.3 billion our share). This insurance is provided by Nuclear Electric Insurance Limited (NEIL). In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met including decommissioning the plant, toward a shortfall in the decommissioning trust fund. The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If losses incurred at any of the nuclear plants insured under the NEIL policies exceed premiums, reserves and other NEIL resources, we may be subject to retrospective assessments under the current policies of approximately $10.7 million per year. Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on our financial condition and results of operations. Fuel Commitments - ---------------- To supply a portion of the fuel requirements for our generating plants, we have entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 2001, WCNOC's nuclear fuel commitments (our share) were approximately $3.2 million for uranium concentrates expiring in 2003, $0.6 million for conversion expiring in 2003, $22.7 million for enrichment expiring at various times through 2006 and $57.5 million for fabrication through 2025. At December 31, 2001, our coal and coal transportation contract commitments in 2001 dollars under the remaining terms of the contracts were approximately $2.0 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013. At December 31, 2001, our natural gas transportation commitments in 2001 dollars under the remaining terms of the contracts were approximately $56.8 million. The natural gas transportation contracts provide firm 97
service to several of our gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016. Energy Act - ---------- As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and decommissioning fund. Our portion of the assessment for Wolf Creek is approximately $9.6 million, payable over 15 years. Such costs are recovered through the ratemaking process. 15. PNM MERGER AND SPLIT-OFF OF WESTAR INDUSTRIES PNM Transaction - --------------- On November 8, 2000, we entered into an agreement with Public Service Company of New Mexico (PNM), pursuant to which PNM would acquire our electric utility businesses in a tax-free stock-for-stock merger. Under the terms of the agreement, both PNM and we are to become subsidiaries of a new holding company, subject to customary closing conditions including regulatory and shareholder approvals. Immediately prior to closing, all of the Westar Industries common stock we own would be distributed to our shareholders in exchange for a portion of their Western Resources common stock. At the same time we entered into the agreement with PNM, we and Westar Industries entered into an Asset Allocation and Separation Agreement which, among other things, provided for this split-off and related matters. On October 12, 2001, PNM filed a lawsuit against us in the Supreme Court of the State of New York. The lawsuit seeks, among other things, declaratory judgment that PNM is not obligated to proceed with the proposed merger based in part upon the KCC orders discussed below and other KCC orders reducing rates for our electric utility business. PNM believes the orders constitute a material adverse effect and make the condition that the split-off of Westar Industries occur prior to closing incapable of satisfaction. PNM also seeks unspecified monetary damages for breach of representation. On November 19, 2001, we filed a lawsuit against PNM in the Supreme Court of the State of New York. The lawsuit seeks substantial damages for PNM's breach of the merger agreement providing for PNM's purchase of our electric utility operations and for PNM's breach of its duty of good faith and fair dealing. In addition, we filed a motion to dismiss or stay the declaratory judgment action previously filed by PNM seeking a declaratory judgment that PNM has no further obligations under the merger agreement. On January 7, 2002, PNM sent a letter to us purporting to terminate the merger in accordance with the terms of the merger agreement. We have notified PNM that we believe the purported termination of the merger agreement was ineffective and that PNM remains obligated to perform thereunder. We intend to contest PNM's purported termination of the merger agreement. However, based upon PNM's actions and the related uncertainties, we believe the closing of the proposed merger is not likely. KCC Proceedings and Orders - -------------------------- The merger with PNM contemplated the completion of a rights offering for shares of Westar Industries prior to closing. On May 8, 2001, the KCC opened an investigation of the proposed separation of our electric utility businesses from our non-utility businesses, including the rights offering, and other aspects of our unregulated businesses. The order opening the investigation indicated that the investigation would focus on whether the separation and other transactions involving our unregulated businesses are consistent with our obligation to provide efficient and sufficient electric service at just and reasonable rates to our electric utility customers. The KCC staff was directed to investigate, among other matters, the basis for and the effect of the Asset Allocation and Separation Agreement we entered into with Westar Industries in connection with the proposed separation and the intercompany payable owed by us to Westar Industries, the separation of Westar Industries, the effect of the business difficulties faced by our unregulated businesses and whether they should continue to be affiliated with our electric utility business, and our present and prospective capital structures. On May 22, 2001, the KCC issued an order nullifying 98
the Asset Allocation and Separation Agreement, prohibiting Westar Industries and us from taking any action to complete the rights offering for common stock of Westar Industries, which was to be a first step in the separation, and scheduling a hearing to consider whether to make the order permanent. On July 20, 2001, the KCC issued an order that, among other things: (1) confirmed its May 22, 2001 order prohibiting us and Westar Industries from taking any action to complete the proposed rights offering and nullifying the Asset Allocation and Separation Agreement; (2) directed us and Westar Industries not to take any action or enter into any agreement not related to normal utility operations that would directly or indirectly increase the share of debt in our capital structure applicable to our electric utility operations, which has the effect of prohibiting us from borrowing to make a loan or capital contribution to Westar Industries; and (3) directed us to present a financial plan consistent with parameters established by the KCC's order to restore financial health, achieve a balanced capital structure and protect ratepayers from the risks of our non-utility businesses. In its order, the KCC also acknowledged that we are presently operating efficiently and at reasonable cost and stated that it was not disapproving the PNM transaction or a split-off of Westar Industries. We appealed the orders issued by the KCC to the District Court of Shawnee County, Kansas. On February 5, 2002, the District Court issued a decision finding that the KCC orders were not final orders and that the District Court lacked jurisdiction to consider the appeal. Accordingly, the matter was remanded to the KCC for review of the financial plan. On February 11, 2002, the KCC issued an order primarily related to procedural matters for the review of the financial plan, as discussed below. In addition, the order required that we and the KCC staff make filings addressing whether the filing of applications by us and KGE at FERC, seeking renewal of existing borrowing authority, violated the July 20, 2001 KCC order directing that we not increase the share of debt in our capital structure applicable to our electric utility operations. The KCC staff subsequently filed comments asserting that the refinancing of existing indebtedness with new indebtedness secured by utility assets would in certain circumstances violate the July 20, 2001 KCC order. The KCC filed a motion to intervene in the proceeding at FERC asserting the same position. We are unable to predict whether the KCC will adopt the KCC staff position, the extent to which FERC will incorporate the KCC position in orders renewing our borrowing authority, or the impact of the adoption of the KCC staff position, if that occurs, on our ability to refinance indebtedness maturing in the next several years. Our inability to refinance existing indebtedness on a secured basis would likely increase our borrowing costs and adversely affect results of operations. The Financial Plan - ------------------ The July 20, 2001 KCC order directed us to present a financial plan to the KCC. We presented a financial plan to the KCC on November 6, 2001, which we amended on January 29, 2002. The principal objective of the financial plan is to reduce our total debt as calculated by the KCC to approximately $1.8 billion, a reduction of approximately $1.2 billion. The financial plan contemplates that we will proceed with a rights offering and that, in the event that the PNM merger and related split-off do not close, we will use our best efforts to sell our share of Westar Industries common stock, or shares of our common stock, upon the occurrence of certain events. The KCC has scheduled a hearing on May 31, 2002 to review the financial plan. We are unable to predict whether or not the KCC will approve the financial plan or what other action with respect to the financial plan the KCC may take. The financial plan provides that: . Westar Industries will use its best efforts to sell at least 4.14 million shares of its common stock, representing approximately 5.1% of its outstanding shares, but no more than the number of shares of its common stock (approximately 19.13 million shares) representing 19.9% of its outstanding shares. After the offering, we would continue to own 77.0 million shares representing between 80.1% and 94.9% of Westar Industries' outstanding shares. The offering will remain open for no less than 45 calendar days. . In the rights offering, each of our shareholders will receive the right to purchase one share of Westar Industries' common stock for every three shares of our stock held on the record date of the offering. There will be no over-subscription privilege in the offering. However, each shareholder participating in the offering will be issued, with respect to each right exercised in the offering, a warrant to purchase 99
from Westar Industries two shares of its common stock at the subscription price in the offering, subject to proration so that in no event will we hold less than 80.1% of Westar Industries' outstanding shares. This right will be exercisable at any time in the 30-day period preceding January 31, 2003. . So long as we and Westar Industries are tax consolidated, Westar Industries' common stock sold in the offering will have one vote per share and Westar Industries common stock held by us will have 10 votes per share. Any shares sold by us will automatically convert to shares with one vote per share. . The exercise price in the offering will be a fixed price determined on the day the offer is mailed to shareholders by calculating the "Westar Industries Valuation" as set forth in an exhibit to the plan and then applying a 10% initial public offering discount. . Westar Industries will have a rescission right through December 31, 2002. This will give Westar Industries the right to repurchase the shares sold in the rights offering at a price equal to the greater of (i) 1.05 times the exercise price, or (ii) the market price at the time of the repurchase offer. The warrants issued to participating shareholders in the offering will expire if the rescission right is exercised. We would not be able to sell any additional shares prior to the expiration of the rescission period. . The proceeds from the offering (or any other subsequent sale of stock by Westar Industries) and any dividends from the ONEOK common or convertible preferred stock not used in Westar Industries' business or previously committed will be used to purchase in the market our or KGE's currently outstanding debt securities. On February 10, 2003, such debt securities and the balance, if any, of our intercompany payable with Westar Industries will be converted into our common stock at the average trading price for the 20 days prior to conversion, but in no event less than $24 per share. However, if the PNM transaction is not terminated, such funds and the intercompany payable will be transferred by us to Westar Industries to purchase 7.5% Western Resources convertible preferred stock, convertible into our common stock at $30 per share, as provided in the PNM merger agreement. Prior to tax deconsolidation, Westar Industries cannot receive any cash dividends from us, but will instead reinvest those dividends in additional shares of our common stock. Dividends on the convertible preferred stock will be payable in additional preferred shares rather than cash. Westar Industries will use interest received on our and KGE debt securities it purchases as provided above to purchase additional debt securities. . If the PNM transaction is not terminated, the amount of our convertible preferred stock purchased by Westar Industries will not exceed $291 million. Westar Industries will continue to own our common stock it currently owns. Westar Industries will retain its option to purchase Westar Generating, Inc., a wholly owned subsidiary of ours, which owns an interest in the State Line Facility (see "Item 2. Properties" for a description of this facility and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Information -- Related Party Transactions" for a discussion of this purchase option). . Westar Industries will not vote any of our common stock it owns as long as we are tax consolidated. . Westar Industries will adopt a "poison pill" that will restrict ownership in it to 20% of the shares not owned by us. . The rights offering and subsequent sale of Westar Industries' shares by us pursuant to the plan do not constitute a change in control for our employees under the terms of existing agreements and no agreements will be executed which include a provision under which the offering and sale of Westar Industries' shares by us pursuant to the plan would constitute a change in control. . We will not sell more than 19.9% of Westar Industries unless we have $1.8 billion or less in short- and long-term debt and all of our and KGE's first mortgage bonds are rated investment grade. 100
. In the event Westar Industries' common stock trades for 45 consecutive trading days at a price that is 15% above the price necessary to reduce our short- and long-term debt to an amount less than $1.8 billion (as measured at the end of the immediately preceding fiscal quarter), we will be required to use our best efforts to sell enough shares in Westar Industries, or us, or a combination of both (at our option), to reduce debt to $1.8 billion. However, in no event shall this obligation be triggered prior to February 1, 2003, unless the PNM transaction is terminated prior to that date. Furthermore, on each annual anniversary of the closing of the rights offering, the amount of debt used to determine whether our obligation has been triggered will increase by $100 million. . We agree to reduce our total debt by at least $100 million per year each year following the completion of the offering until the separation is consummated. . Our board of directors will have at least a majority of independent directors following the separation. 16. 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 us with respect to securities of ADT Ltd. We have cooperated with the SEC staff in this investigation. We, Westar Industries, Protection One, its subsidiary Protection One Alarm Monitoring, Inc. (Protection One Alarm 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, "Alec Garbini, 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. On February 27, 2001, plaintiffs filed a Third Consolidated Amended Class Action Complaint (Third Amended Complaint). Plaintiffs purported to bring the action on behalf of a class consisting of all purchasers of publicly traded securities of Protection One, including common stock and bonds, during the period of February 10, 1998 through February 2, 2001. The Third Amended Complaint asserted claims under Section 11 of the Securities Act of 1933 and Section 10(b) of the Securities Exchange Act of 1934 against Protection One, Protection One Alarm 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, 1998, 1999 and the first three quarters of 2000 were false and misleading and not in compliance with generally accepted accounting principles. Plaintiffs alleged, 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 Third Amended Complaint further asserted claims against us and Westar Industries 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 was also asserted under Section 11 of the Securities Act of 1933 against Protection One's auditor, Arthur Andersen LLP. The Third Amended Complaint sought an unspecified amount of compensatory damages and an award of fees and expenses, including attorneys' fees. On June 4, 2001, the District Court dismissed plaintiffs' claims under Sections 10(b) and 20(a) of the Securities Exchange Act. The Court granted plaintiffs leave to replead such claims. The Court also dismissed all claims brought on behalf of bondholders with prejudice. The Court also dismissed plaintiffs' claims against Arthur Andersen and the plaintiffs have appealed that dismissal. On February 22, 2002, plaintiffs filed a Fourth Consolidated Amended Class Action Complaint. The new complaint realleges claims on behalf of purchasers of common stock 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. The defendants have until April 5, 2002 to respond to the new complaint. Protection One and we cannot predict the impact of this litigation, which could be material. We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provision has been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect upon our overall financial position or results of operations. See also Notes 3 and 15 for discussion of FERC proceedings and the lawsuit PNM filed against us and the KCC regulatory proceedings. 101
17. LEASES At December 31, 2001, we had leases covering various property and equipment. Rental payments for operating leases ranging from 1 to 17 years and estimated rental commitments are as follows: LaCygne 2 Total Year Ended December 31, Lease (a) Leases - ------------------------------------------------------ ---------- -------- (In Thousands) Rental payments: 1999 .............................................. $ 34,598 $ 71,771 2000 .............................................. 34,598 71,232 2001 .............................................. 34,598 75,259 Future commitments: 2002 .............................................. $ 34,598 $ 69,897 2003 .............................................. 39,420 66,772 2004 .............................................. 34,598 58,492 2005 .............................................. 38,013 57,983 2006 .............................................. 42,287 61,309 Thereafter ........................................ 422,318 516,318 -------- -------- Total future commitments ....................... $611,234 $830,771 ======== ======== - ---------- (a) LaCygne 2 lease amounts are included in total leases. In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operation and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the initial lease term. In 1992, we deferred costs associated with the refinancing of the secured facility bonds of the Trustee and owner of LaCygne 2. These costs are being amortized over the life of the lease and are included in operating expense. 18. COMMON STOCK, PREFERRED STOCK AND OTHER MANDATORILY REDEEMABLE SECURITIES Our Restated Articles of Incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2001, 86,205,417 shares were issued and outstanding, including shares owned by Westar Industries. We have a Direct Stock Purchase Plan (DSPP). Shares issued under the DSPP may be either original issue shares or shares purchased on the open market. During 2001, a total of 16,643,403 shares were purchased from the company through the issuance of 16,123,103 original issue shares and 520,300 treasury shares. Of the total shares purchased from us in 2001, 15,047,987 were acquired by Westar Industries and the balance of the shares were for the DSPP, ESPP, 401(k) match and other stock based plans operated under the 1996 Long-Term Incentive and Share Award Plan. At December 31, 2001, 4,300,577 shares were available under the DSPP registration statement. In 2000, we purchased 540,000 shares of our common stock at an average price of $17.01. All of these shares were reissued during the year. 102
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 our option. Total Principal Call Amount Rate Outstanding Price Premium to Redeem ------ ----------- ------- --------- ----------- (Dollars in Thousands) 4.500% $ 13,445 108.00% $ 1,076 $ 14,521 4.250% 5,841 101.50% 88 5,929 5.000% 4,650 102.00% 93 4,743 ----------- --------- ----------- $ 23,936 $ 1,257 $ 25,193 =========== ========= =========== The provisions of our Restated Articles of Incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. 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 us. 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 ours, 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 us. 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 our obligations under the Subordinated Debentures discussed above, we have agreed to guarantee, on a subordinated basis, payment of distributions on the preferred securities. These undertakings constitute a full and unconditional guarantee by us of the trust's obligations under the preferred securities. Treasury Stock - -------------- At December 31, 2001, all of our treasury stock was owned by Westar Industries, except for 50,000 shares owned by Protection One. 103
19. RELATED PARTY TRANSACTIONS Below we describe significant transactions between us and Westar Industries and other subsidiaries and related parties. We have disclosed significant transactions even if these have been eliminated in the preparation of our consolidated results and financial position since our proposed financial plan, as discussed in Note 15, calls for a split-off of Westar Industries from us to occur in the future. We cannot predict whether the KCC will aprove the plan and if so whether we will be successful in executing the plan. We and ONEOK have shared services agreements in which we provide and bill one another for facilities, utility field work, information technology, customer support and bill processing. Payments for these services are based on various hourly charges, negotiated fees and out-of-pocket expenses. 2001 2000 1999 ------ ------ ------ (In Thousands) Charges to ONEOK ........................ $8,202 $8,463 $8,876 Charges from ONEOK ...................... 3,279 3,420 3,322 Net receivable from ONEOK, outstanding at December 31 ............ 1,424 1,205 1,506 In 1999, we and Protection One have entered into a service agreement pursuant to which we provide administrative services, including accounting, human resources, legal, facilities and technology services on a year to year basis. Fees for these services are based upon various hourly charges, negotiated fees and out-of-pocket expenses. Protection One incurred charges of $8.1 million in 2001, $7.3 million in 2000 and $2.0 million in 1999. These intercompany charges have been eliminated in consolidation. We had a payable to Westar Industries of approximately $67.7 million at December 31, 2001 on which we paid interest at the rate of 8.5% per annum. On February 28, 2001, Westar Industries converted $350.0 million of the then outstanding payable balance into approximately 14.4 million shares of our common stock, representing 16.9% of our outstanding common stock after conversion. These shares are reflected as treasury stock in our consolidated balance sheets. During the first quarter of 2002, we repaid the remaining balance owed to Westar Industries. The proceeds were used by Westar Industries to purchase our outstanding debt in the open market. At February 28, 2002, Westar Industries owned $118.7 million of our debt. Amounts outstanding and interest earned by Westar Industries have been eliminated in our consolidated financial statements. See Note 2 "Summary of Significant Accounting Policies -- Principles of Consolidation." Westar Industries is the lender under Protection One's senior credit facility. On November 1, 2001, this facility was amended to, among other things, extend the maturity date to January 3, 2003, and provide for a quarterly fee for financial advisory and management services equal to 1/8% of Protection One's consolidated total assets at the end of each quarter, beginning with the quarter ending March 31, 2002. As of December 31, 2001, approximately $137.5 million was drawn under the facility. On March 25, 2002, Westar Industries further amended the facility to increase the amount of the facility to $180 million. Amounts outstanding have been eliminated in our consolidated financial statements. We have a tax sharing agreement with Protection One. This pro rata tax sharing agreement allows Protection One to be reimbursed for current tax benefits utilized in our consolidated tax return. We and Protection One are eligible to file on a consolidated basis for tax purposes as long as we maintain an 80% ownership interest in Protection One. We reimbursed Protection One $11.8 million for tax year 2001 and $7.4 million for tax year 2000 for the current tax benefit. During 2001, Westar Industries purchased $37.9 million face value of Protection One bonds on the open market. In October 2001, $27.6 million of these bonds were transferred to Protection One in exchange for cash. In 2001, we recognized an extraordinary gain from the purchase of Protection One bonds of $22.3 million, net of tax of $12.0 million. During 2000, Westar Industries purchased $170.0 million face value of Protection One bonds on the open market. In exchange for cash and the settlement of certain intercompany payables and receivables, $103.9 104
million of these debt securities were transferred to Protection One. The balance of the bonds was sold to Protection One in March 2001. No gain or loss was recognized on these transactions. In the latter part of 2001 through February 28, 2002, Protection One purchased approximately $1.8 million of our preferred stock in open market purchases. These purchases have been accounted for as retirements. During 2001, we extended loans to our officers for the purpose of purchasing shares of our common stock on the open market. The loans are unsecured and contain a variable interest rate that is equal to our short term borrowing rate. Interest is payable quarterly. The loans mature and become due on December 4, 2004. The balance outstanding at December 31, 2001 was approximately $2.0 million and is classified as a reduction to shareholders' equity in the accompanying consolidated balance sheet. The maximum amount of loans authorized is $7.9 million. During the fourth quarter of 2001, KGE entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One for approximately $0.5 million. The sales price was determined by management based on three independent appraisers' findings. On February 29, 2000, Westar Industries purchased the European operations of Protection One, and certain investments held be a subsidiary of Protection One for an aggregate purchase price of $244 million. Westar Industries paid approximately $183 million in cash and transferred Protection One debt securities with a market value of approximately $61 million to Protection One. Westar Industries 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 Industries on Protection One's revolving credit facility. No gain or loss was recorded on this intercompany transaction and the net book value of the assets was unaffected. If the KCC approves our financial plan, at the closing of the proposed rights offering, we would enter into an option agreement that grants Westar Industries an option to purchase the stock of Westar Generating, Inc., a wholly owned subsidiary that owns our interest in the State Line generating facility. The option would be exercisable at any time during the three year period following execution of the agreement, subject to extension for two additional one year periods. The option price is based on net book value at the time of exercise. The option would be exercisable only if Westar Industries is unable to obtain a permanent exemption from registration under the Investment Company Act of 1940. 20. WORK FORCE REDUCTIONS In late 2001, we reduced our utility work force by approximately 200 employees through involuntary separations and recorded a severance-related net charge of approximately $14.3 million. In 2001, Protection One also reduced its work force by approximately 500 employees in connection with facility consolidations and recorded a severance-related net charge of approximately $3.1 million. In the first quarter of 2002, we further reduced our utility work force by approximately 400 employees through a voluntary separation program. We expect to record a net charge of approximately $21.1 million in the first quarter of 2002 related to this program. We may replace some of these employees. Protection One also reduced its work force by approximately 200 employees in connection with facility consolidations and expects to record a net severance charge of approximately $0.5 million in the first quarter of 2002. 21. MONITORED SERVICES DISPOSITIONS In 2001, Protection One and Protection One Europe disposed of certain monitored security operations for approximately $48.0 million and we recorded a pre-tax loss of $13.1 million. 105
In 1999, Protection One sold the assets that comprised its Mobile Services Group. Cash proceeds of this sale approximated $20 million and Protection One recorded a pre-tax gain of approximately $17 million. This gain is reflected in Other Income on our consolidated statements of income. 22. INTERNATIONAL POWER DEVELOPMENT COSTS In 1998 we made a decision to terminate the employment of all employees, close offices, discontinue all development activities, and terminate all other matters related to the activity of The Wing Group. 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 and charged to income in 1998. This was accounted for as a change in estimate in 1999. The excess accrual was credited to income in 1999 and reduced our selling, general and administration costs for that period. 23. MARKETABLE SECURITIES During the last three years, we sold substantially all of our investments in marketable securities. These securities were classified as available-for-sale. Realized gains and losses are included in earnings and were derived using the specific identification method. The following table summarizes our marketable security sales for the years ended December 31, 2001, 2000 and 1999: Marketable Security Sales ------------------------------- 2001 2000 1999 ------ -------- ------- (Dollars in Thousands) Sales proceeds $2,829 $218,609 $73,456 Realized gains (a) -- 115,987 12,587 Realized losses 1,861 1,039 38,838 ---------- (a) During 2000, we sold our equity investment in a gas compression company and realized a pre-tax gain of $91.1 million. In 1999, we determined that the decline in value of our investments in paging industry companies was other than temporary and a charge to earnings for the decline in value was required. This non-cash charge of $76.2 million was recorded in the fourth quarter of 1999 and is presented separately in our consolidated statements of income. In February 2000, one of the paging companies we held an interest in made an announcement that significantly increased the market value of paging company securities general. During the first quarter of 2000, we sold the remainder of these securities for a gain of $24.9 million. During 2001, we wrote down the cost basis of certain equity securities to their fair value. The fair value of these equity securities had declined below our cost basis, and we determined that the decline was other than temporary. The amount of the write down totaled $11.1 million, of which $9.6 million related to a cost method investment. The write down is included in other income (expense). 24. SEGMENTS OF BUSINESS In 1998, we adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement requires us to define and report our business segments based on how management currently evaluates its business. Our business is segmented based on differences in products and services, production processes and management responsibility. Based on this approach, we have identified five reportable segments: Fossil Generation, Nuclear Generation, Customer Operations, Monitored Services and Other. The Fossil Generation, Nuclear Generation and Customer Operations segments comprise our electric utility business. Fossil 106
Generation produces power for sale internally to the Customer Operations segment and externally to wholesale customers. A component of our Fossil Generation segment is power marketing, which attempts to minimize commodity price risk associated with fuel purchases and purchased power requirements. Power marketing also attempts to maximize utilization of generation capacity and enhance system reliability through sales to external customers as discussed further below. Nuclear Generation represents our 47% ownership in the Wolf Creek Generating Station (Wolf Creek). This segment has only internal sales because it provides all of its power to its co-owners. The Customer Operations segment consists of the transmission and distribution of power to our retail customers in Kansas and the customer service provided to these customers and the transmission of wholesale energy. Monitored Services is comprised of our security alarm monitoring business in North America and Europe. Other includes a 45% interest in ONEOK, investments in international power generation facilities and other investments, which in the aggregate are not material to our business or results of operations. The accounting policies of the segments are substantially the same as those described in Note 2 "Summary of Significant Accounting Policies." Segment performance is based on earnings before interest and taxes (EBIT). Unusual items, such as charges to income and changes in accounting principle, may be excluded from segment performance depending on the nature of the charge or income. Interest expense is excluded from the segment analysis. Our ONEOK investment, marketable securities investments and other equity method investments do not represent operating segments of ours. We have no single external customer from whom we receive ten percent or more of our revenues. Year Ended December 31, 2001 - ---------------------------- Eliminating/ Fossil Nuclear Customer Monitored Reconciling Generation(a) Generation Operations Services Other Items Total ------------- ---------- ---------- ---------- ---------- ------------ ---------- (In Thousands) External sales .................... $ 667,953 $ -- $1,100,443 $ 416,509 $ 1,360 $ (3) $2,186,262 Internal sales .................... 560,528 117,659 317,056 -- -- (995,243) -- Depreciation and amortization ................... 65,875 41,046 78,235 228,123 363 -- 413,642 Earnings (loss) before interest and taxes and cumulative effect of accounting change .............. 120,530 (19,078) 131,917 (126,076) 32,651 (15,321) 124,623 Interest expense .................. 268,224 Earnings (loss) before income taxes ........................... (143,601) Additions to property, plant and equipment ............ 116,595 27,349 83,052 9,456 -- -- 236,452 Customer account acquisitions ................... -- -- -- 36,488 -- -- 36,488 Identifiable assets ............... 1,733,743 1,042,563 1,843,865 1,887,210 1,005,684 -- 7,513,065 107
Year Ended December 31, 2000 - ---------------------------- Eliminating/ Fossil Nuclear Customer Monitored Reconciling Generation Generation Operations Services Other (c) Items (b) Total ---------- ---------- ---------- ---------- ---------- ------------ ---------- (In Thousands) External sales ................... $ 705,536 $ -- $1,123,590 $ 537,859 $ 1,484 $ 7 $2,368,476 Internal sales ................... 572,533 107,770 291,927 -- -- (972,230) -- Depreciation and amortization .... 60,331 40,052 75,419 248,414 2,116 37 426,369 Earnings (loss) before interest and taxes ............ 202,744 (24,323) 171,872 (91,370) 189,289 (21,533) 426,679 Interest expense 289,568 Earnings before income taxes ..... 137,111 Additions to property, plant and equipment ................. 162,570 25,877 96,984 20,070 2,572 -- 308,073 Customer account acquisitions .... -- -- -- 47,261 -- -- 47,261 Identifiable assets .............. 1,658,986 1,064,817 1,893,884 2,175,381 1,008,654 (2) 7,801,720 Year Ended December 31, 1999 - ---------------------------- Eliminating/ Fossil Nuclear Customer Monitored Reconciling Generation Generation Operations Services Other (d) Items (b) Total ---------- ---------- ---------- ---------- ---------- ------------ ---------- (In Thousands) External sales ................... $ 365,311 $ -- $1,064,385 $ 599,105 $ 1,284 $ 2 $2,030,087 Internal sales ................... 546,683 108,445 293,522 -- -- (948,650) -- Depreciation and amortization .... 55,320 39,629 71,717 233,906 3,007 90 403,669 Earnings (loss) 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) Additions to property, plant and equipment ................. 143,904 10,036 89,162 12,437 20,205 -- 275,744 Customer account acquisitions .... -- -- -- 268,409 -- -- 268,409 Identifiable assets .............. 1,476,716 1,083,344 1,783,937 2,539,921 1,165,145 (59,171) 7,989,892 - ---------- (a) EBIT shown above for Fossil Generation does not include the unrealized gain on derivatives reported as a cumulative effect of a change in accounting principle. If the effect had been included, EBIT for the Fossil Generation segment for the year ended December 31, 2001 would have been $151.6 million. (b) Identifiable assets include eliminating and reclassing balances to consolidate the monitored services business. (c) EBIT includes the gain on the sale of our investment in a gas compression company of $91.1 million and the gain on the sale of other marketable securities of $24.9 million. (d) 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. 108
Geographic Information - ---------------------- Our sales and property, plant and equipment are as follows: For the Year Ended December 31, ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- (In Thousands) External sales: United States operations ........... $2,102,598 $2,254,105 $1,859,008 International operations ........... 83,664 114,371 171,079 ---------- ---------- ---------- Total .......................... $2,186,262 $2,368,476 $2,030,087 ========== ========== ========== As of December 31, ------------------------------------ 2001 2000 1999 ---------- ---------- ---------- (In Thousands) Property, plant and equipment, net: United States operations ........... $4,038,648 $3,984,858 $3,880,865 International operations ........... 4,204 8,580 8,579 ---------- ---------- ---------- Total .......................... $4,042,852 $3,993,438 $3,889,444 ========== ========== ========== 25. IMPAIRMENT CHARGE PURSUANT TO NEW ACCOUNTING RULES Effective January 1, 2002, we adopted the new accounting standards SFAS No. 142, "Accounting for Goodwill and Other Intangible Assets," and SFAS No. 144., "Accounting for the Impairment and Disposal of Long-Lived Assets." SFAS No. 142 establishes new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinues amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. SFAS No. 144 establishes a new approach to determining whether our customer account asset is impaired. The approach no longer permits us to evaluate our customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of the goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream to be used under SFAS No. 144 is limited to the future estimated undiscounted cash flows of our existing customer accounts. Additionally, the new rule no longer permits us to include estimated cash flows from forecasted customer additions. If the undiscounted cash flow stream from existing customer accounts is less than the combined book value of customer accounts and goodwill, an impairment charge is required. The new rule substantially reduces the net undiscounted cash flows used for impairment evaluation purposes as compared to the previous accounting rules. The undiscounted cash flow stream has been reduced from the 16-year remaining life of the goodwill to the nine-year remaining life of customer accounts for impairment evaluation purposes and does not include estimated cash flows from forecasted customer additions. 109
To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of goodwill and customer accounts. Based on this analysis, during the first quarter of 2002, we will record a non-cash net charge of approximately $653.7 million, of which $464.2 million is related to goodwill and $189.5 million is related to customer accounts. The charge is detailed as follows: Impairment of Impairment of Goodwill Customer Accounts Total ------------- ----------------- --------- (In Thousands) Protection One ................ $498,921 $334,064 $ 832,985 Protection One Europe ......... 80,104 -- 80,104 -------- -------- -------- Total pre-tax impairment ...... $579,025 $334,064 913,089 ======== ======== Income tax benefit ............ (173,650) Minority interest ............. (85,713) --------- Net charge .................... $ 653,726 ========= The impairment charge for goodwill will be reflected in our consolidated statement of income as a cumulative effect of a change in accounting principle. The impairment charge for customer accounts will be reflected in our consolidated statement of income as an operating cost. These impairment charges reduce the recorded value of these assets to their estimated fair values at January 1, 2002. In 2001, we recorded approximately $57.1 million of goodwill amortization expense. We will no longer be permitted to amortize goodwill to income because of adoption of the new goodwill rule. In 2001, we recorded approximately $153.0 million of customer account amortization expense. Future customer account amortization expense will also be reduced as a result of the impairment charge. We will be required to perform impairment tests for our monitored services segment for long-lived assets prospectively as long as it continues to incur recurring losses or for other matters that may negatively impact its businesses. Goodwill will be required to be tested each year for impairment. Declines in market values of our monitored services businesses or the value of customer accounts that may be incurred prospectively may require additional write down of these assets in the future. Estimated Lives of Customer Accounts to Change Based on Customer Account Lifing - ------------------------------------------------------------------------------- Study Results - ------------- Protection One is currently evaluating the estimated life and amortization rates for customer accounts, given the results of a lifing study performed by a third party appraisal firm in the first quarter of 2002. Any change in its amortization rate or estimated life will be determined in the first quarter of 2002 and accounted for prospectively as a change in estimate. 26. SUBSEQUENT EVENTS Ice Storm - --------- In late January 2002, a severe ice storm swept through our utility service area causing extensive damage and loss of power to numerous customers. We estimate storm restoration costs could run as high as $25 million. On March 13, 2002, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery costs related to storm restoration. We cannot predict whether the KCC will approve our application. 110
27. QUARTERLY RESULTS (UNAUDITED) The amounts in the table are unaudited but, in the opinion of management, contain all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results of such periods. Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. First Second Third Fourth ---------- ---------- ---------- ---------- (In Thousands, Except Per Share Amounts) 2001 - ---- Sales ................................................... $ 560,741 $ 522,901 $ 667,068 $ 435,552 Gross profit ............................................ 290,162 285,597 357,077 253,876 Net income (loss) before extraordinary gain and accounting change .................................... (19,187) (36,014) 26,722 (34,247) Net income (loss) ....................................... 4,450 (30,188) 35,976 (31,114) Earnings (loss) per share available for common stock before extraordinary gain and accounting change: Basic .......................................... $ (0.28) $ (0.51) $ 0.38 $ (0.49) Diluted ........................................ $ (0.28) $ (0.51) $ 0.37 $ (0.48) Cash dividend per common share .......................... $ 0.30 $ 0.30 $ 0.30 $ 0.30 Market price per common share: High ........................................... $ 25.875 $ 25.820 $ 22.900 $ 17.801 Low ............................................ $ 21.800 $ 20.000 $ 15.620 $ 16.000 2000 - ---- Sales ................................................... $ 481,699 $ 546,607 $ 759,562 $ 580,608 Gross profit ............................................ 306,760 331,889 395,534 298,461 Net income (loss) before extraordinary gain and accounting change .................................... 39,801 23,565 53,991 (26,307) Net income (loss) ....................................... 54,483 40,912 60,707 (19,621) Earnings (loss) per share available for common stock before extraordinary gain and accounting change: Basic .......................................... $ 0.58 $ 0.34 $ 0.78 $ (0.40) Diluted ........................................ $ 0.58 $ 0.34 $ 0.77 $ (0.39) Cash dividend per common share .......................... $ 0.535 $ 0.30 $ 0.30 $ 0.30 Market price per common share: High ........................................... $ 18.313 $ 17.813 $ 21.953 $ 25.875 Low ............................................ $ 15.313 $ 14.688 $ 15.375 $ 20.438 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND - ----------------------------------------------------------------------- FINANCIAL DISCLOSURE -------------------- None. 111
PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT - ----------------------------------------------------------- The information relating to our Directors required by Item 10 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. 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 us with the SEC. 112
EXECUTIVE OFFICERS OF THE COMPANY Other Offices or Positions Name Age Present Office Held During the Past Five Years - ---- --- -------------- ------------------------------- David C. Wittig 46 Chairman of the Board -- (since January 1999) Chief Executive Officer (since July 1998) and President (since March 1996) Douglas T. Lake 51 Director Bear Stearns & Co., Inc. - (since October 2000) Senior Managing Director Executive Vice President, (1995 to August 1998) Chief Strategic Officer (since September 1998) Richard A. Dixon 58 Senior Vice President, Customer Operations Western Resources, Inc. - (since October 2001) Vice President, Transmission Services (May 2000 to October 2001) Executive Director, System Operations (January 1999 to April 2000) Executive Director, Transmission Services (September 1996 to December 1998) Paul R. Geist 38 Senior Vice President, Chief Financial Western Resources, Inc. - Officer and Treasurer (since October Vice President, Corporate Development (February 2001) 2001 to October 2001) Executive Director, Corporate Strategy (November 1999 to February 2001) Panera Bread Company - Vice President - Finance (October 1998 to November 1999) Houlihan's Restaurant Group, Inc. - Executive Vice President - Chief Financial Officer (1997 to October 1998) Vice President/Controller (1995 to 1997) Shane A. Mathis 31 Senior Vice President, Commodity Strategy Western Resources, Inc. - (since October 2001) Vice President, Commodity Strategy (October 2000 to October 2001) Vice President, Risk Management (May 2000 to October 2000) Executive Director, Gas and Liquids (March 2000 to May 2000) Executive Director, Risk Management (January 1998 to March 2000) Director, Energy Trading (January 1998 to August 1998) Senior Strategist (February 1997 to January 1998) Merrill Lynch - Financial Consultant (1995 to February 1997) Douglas R. Sterbenz 38 Senior Vice President, Generation and Western Resources, Inc. - Marketing (since October 2001) Manager, Bulk Power Marketing (August 1998 to October 2001) Energy Trader (May 1997 to July 1998) Questar Energy Trading - Director, Power Marketing (April 1996 to May 1997) 113
ITEM 11. EXECUTIVE COMPENSATION - ------------------------------- The information required by Item 11 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. 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 us with the SEC. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT - ----------------------------------------------------------------------- The information required by Item 12 is set forth in our definitive proxy statement to be filed with the SEC for our 2002 Annual Meeting of Shareholders to be held on June 11, 2002. 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 us with the SEC. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - ------------------------------------------------------- None. 114
PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K - ------------------------------------------------------------------------ FINANCIAL STATEMENTS INCLUDED HEREIN Report of Independent Public Accountants Consolidated Balance Sheets, December 31, 2001 and 2000 Consolidated Statements of Income for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999 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 FILED DURING THE QUARTER ENDED DECEMBER 31, 2001: Form 8-K filed October 16, 2001 - Announcement that PNM filed a lawsuit against us in New York court seeking monetary damages for breach of representation and seeking, among other things, to terminate the merger agreement. Form 8-K filed October 26, 2001 - Announcement of changes in our Direct Stock Purchase Plan. Form 8-K filed November 6, 2001 - Announcement that we filed a financial plan with the KCC. Form 8-K filed November 20, 2001 - Announcement that we filed a lawsuit against PNM in New York court seeking substantial damages for PNM's breach of the merger agreement. Form 8-K filed December 6, 2001 - Announcement of our expected 2002 operating results. 115
EXHIBIT INDEX All exhibits marked "I" are incorporated herein by reference. All exhibits marked by an asterisk are management contracts or compensatory plans or arrangements required to be identified by Item 14(a)(3) of Form 10-K. Description ----------- 2(a) -Agreement and Plan of Restructuring and Merger, dated as of I November 8, 2000 among the company, Public Service Company of New Mexico, HVOLT Enterprises, Inc., HVK, Inc., and HVNM, Inc. (filed as Exhibit 99.1 to the November 17, 2000 Form 8-K) 3(a) -By-laws of the company, as amended March 16, 2000 (filed as Exhibit I 3(a) to December 1999 Form 10-K) 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) 3(c) -Certificate of Amendment to Restated Articles of Incorporation of I 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 (filed as Exhibit 3(d) to December 1993 Form 10-K) 3(e) -Certificate of Correction to Restated Articles of Incorporation of I the company dated December 20, 1991 (filed as Exhibit 3(b) to December 1991 Form 10-K) 3(f) -Certificate of Designations for Preference Stock, 7.58% Series, I without par value, dated April 8, 1992, (filed as Exhibit 3(e) to December 1993 form 10-K) 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) 3(h) -Certificate of Amendment to Restated Articles of Incorporation of I the company dated May 26, 1994 (filed as Exhibit 3 to June 1994 Form 10-Q) 3(i) -Certificate of Amendment to Restated Articles of Incorporation of I the company dated May 14, 1996 (filed as Exhibit 3(a) to June 1996 Form 10-Q) 3(j) -Certificate of Amendment to Restated Articles of Incorporation of I the company dated May 12, 1998 (filed as Exhibit 3 to March 1998 Form 10-Q) 3(k) -Form of Certificate of Designations for 7.5% Convertible Preference I Stock (filed as Exhibit 99.4 to November 17, 2000 Form 8-K) 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, 1939, I April 1, 1949, July 20, 1949, October 1, 1949, December 1, 1949, October 4, 1951, December 1, 1951, May 1, 1952, October 1, 1954, September 1, 1961, April 1, 1969, September 1, 1970, February 1, 1975, May 1, 1976 and April 1, 1977, respectively (filed as Exhibit 4(b) to Registration Statement No. 33-21739) 4(d) -Sixteenth Supplemental Indenture dated June 1, 1977 (filed as I Exhibit 2-D to Registration Statement No. 2-60207) 4(e) -Seventeenth Supplemental Indenture dated February 1, 1978 (filed as I Exhibit 2-E to Registration Statement No. 2-61310) 4(f) -Eighteenth Supplemental Indenture dated January 1, 1979 (filed as I 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 as I Exhibit 4(g) to Registration Statement No. 33-21739) 4(i) -Twenty-First Supplemental Indenture dated April 1, 1982 (filed as I Exhibit 4(h) to Registration Statement No. 33-21739) 4(j) -Twenty-Second Supplemental Indenture dated February 1, 1983 (filed I as Exhibit 4(i) to Registration Statement No. 33-21739) 116
4(k) -Twenty-Third Supplemental Indenture dated July 2, 1986 (filed as I Exhibit 4(j) to Registration Statement No. 33-12054) 4(l) -Twenty-Fourth Supplemental Indenture dated March 1, 1987 (filed as I Exhibit 4(k) to Registration Statement No. 33-21739) 4(m) -Twenty-Fifth Supplemental Indenture dated October 15, 1988 (filed I as Exhibit 4 to the September 1988 Form 10-Q) 4(n) -Twenty-Sixth Supplemental Indenture dated February 15, 1990 (filed I as Exhibit 4(m) to the December 1989 Form 10-K) 4(o) -Twenty-Seventh Supplemental Indenture dated March 12, 1992 (filed I as Exhibit 4(n) to the December 1991 Form 10-K) 4(p) -Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as I Exhibit 4(o) to the December 1992 Form 10-K) 4(q) -Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as I Exhibit 4(p) to the December 1992 Form 10-K) 4(r) -Thirtieth Supplemental Indenture dated February 1, 1993 (filed as I Exhibit 4(q) to the December 1992 Form 10-K) 4(s) -Thirty-First Supplemental Indenture dated April 15, 1993 (filed as I Exhibit 4(r) to Registration Statement No. 33-50069) 4(t) -Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as I Exhibit 4(s) to the December 31, 1994 Form 10-K) 4(u) -Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as I Exhibit 4(v) to the December 31, 2000 Form 10-K) 4(v) -Debt Securities Indenture dated August 1, 1998 (filed as Exhibit I 4.1 to the June 30, 1998 Form 10-Q) 4(w) -Form of Note for $400 million 6.25% Putable/Callable Notes due I August 15, 2018, Putable/Callable August 15, 2003 (filed as Exhibit 4.2 to the 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 10(a) to I the June 1996 Form 10-Q)* 10(b) -Form of Employment Agreements with Messers. Grennan, Koupal, Lake, I Terrill, Wittig and Ms. Sharpe (filed as Exhibit 10(b) to the December 31, 2000 Form 10-K)* 10(c) -A Rail Transportation Agreement among Burlington Northern Railroad I 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. effective I March 31, 1993 (filed as Exhibit 10(a) to the December 31, 1993 Form 10-K) 10(e) -Agreement between the company and Williams Natural Gas Company I dated October 1, 1993 (filed as Exhibit 10(b) to the December 31, 1993 Form 10-K) 10(f) -Deferred Compensation Plan (filed as Exhibit 10(i) to the December I 31, 1993 Form 10-K)* 10(g) -Short-term Incentive Plan (filed as Exhibit 10(k) to the December I 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., as I 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, dated I 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 company I (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 to I 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 I August 17, 1998 * 10(o) -Form of Change of Control Agreement with officers of the company I (filed as Exhibit 10(o) to the December 31, 2000 Form 10-K)* 117
10(p) -Amendment to Outside Directors' Deferred Compensation Plan dated I May 17, 2001 (filed as Exhibit 10(p) to the December 31, 2000 Form 10-K)* 10(q) -Asset Allocation and Separation Agreement, dated as of November 8, I 2000, between the company and Westar Industries, Inc. (filed as Exhibit 99.2 to the November 17, 2000 Form 8-K) 10(r) -Form of loan agreement with officers of the company* 12 -Computations of Ratio of Consolidated Earnings to Fixed Charges 21 -Subsidiaries of the Registrant 23 -Consent of Independent Public Accountants, Arthur Andersen LLP 99(a) -Press release issued August 13, 2001 by PNM announcing that talks I to modify our transaction with PNM have been discontinued (filed as Exhibit 99.1 to the June 30, 2001 Form 10-Q) 99(b) -Press release issued August 13, 2001 by Western Resources I responding to PNM's announcement of discontinued talks (filed as Exhibit 99.2 to the June 30, 2001 Form 10-Q) 99(c) -Letter to the SEC of assurances given by Arthur Andersen LLP regarding their audit of December 31, 2001 financial statements to the company 118
WESTERN RESOURCES, INC. SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands) Balance at Charged to Balance Beginning Costs and at End Description of Period Expenses Deductions of Period - ----------- --------- -------- ---------- --------- (In Thousands) Year ended December 31, 1999 Allowances deducted from assets for doubtful accounts (a) .... $ 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 Year ended December 31, 2000 Allowances deducted from assets for doubtful accounts (a) .... 35,765 23,690 (13,639) 45,816 Accrued exit fees, shut-down and severance costs ............. 380 -- -- 380 Year ended December 31, 2001 Allowances deducted from assets for doubtful accounts (a) .... 45,816 7,075 (33,770) 19,121 Accrued exit fees, shut-down and severance costs (d) ........ 380 -- (337) 43 - ---------- (a) Deductions are the result of write-offs of accounts receivable. (b) Consists of costs to close duplicate facilities and severance and compensation benefits. (c) See Note 22 of the "Notes to Consolidated Financial Statements" for further information. (d) Deductions are the result of payment of accrued severance costs. 119
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: April 1, 2002 By: /s/ Paul R. Geist ------------------------------------- Paul R. Geist, Senior Vice President, Chief Financial Officer and Treasurer SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: Signature Title Date --------- ----- ---- /s/ DAVID C. WITTIG Chairman of the Board, President April 1, 2002 - --------------------------- and Chief Executive Officer (David C. Wittig) (Principal Executive Officer) /s/ PAUL R. GEIST Senior Vice President, Chief April 1, 2002 - --------------------------- Financial Officer and Treasurer (Paul R. Geist) (Principal Financial and Accounting Officer) /s/ FRANK J. BECKER Director April 1, 2002 - --------------------------- (Frank J. Becker) /s/ GENE A. BUDIG Director April 1, 2002 - --------------------------- (Gene A. Budig) /s/ CHARLES Q. CHANDLER, IV Director April 1, 2002 - --------------------------- (Charles Q. Chandler, IV) /s/ JOHN C. DICUS Director April 1, 2002 - --------------------------- (John C. Dicus) /s/ R. A. EDWARDS III Director April 1, 2002 - --------------------------- (R. A. Edwards III) /s/ DOUGLAS T. LAKE Director April 1, 2002 - --------------------------- (Douglas T. Lake) /s/ JOHN C. NETTLES, JR. Director April 1, 2002 - --------------------------- (John C. Nettles, Jr.) 120
Exhibit 10 (r) PROMISSORY NOTE - -------------------------------------------------------------------------------- $________ ________________, 2001 - -------------------------------------------------------------------------------- Topeka, Kansas 1. FOR VALUE RECEIVED, _________________________, an individual ("Debtor"), unconditionally promises to pay to the order of Western Resources, Inc., a Kansas corporation ("Payee"), at its principal business offices located at 818 South Kansas Avenue, Topeka, Kansas 66612, or at any other place designated in writing at any time by the holder hereof, the principal sum of $_______ (or, if less, so much thereof as may have been advanced). 2. Debtor promises to pay principal and interest as follows: (a) Interest shall be due and payable quarterly in arrears commencing on April 10, 2002 and continuing on the tenth day of each July, October, January and April to occur thereafter and on the Maturity Date (as defined below) for the immediately preceding calendar quarter (or other period). (b) The entire unpaid principal balance hereof is due and payable on ________, 2004 (the Maturity Date). 3. Interest shall be payable each quarter on unpaid principal advances at a rate equal to the average daily interest rate paid by Payee during such quarter on all borrowings under Payee's $500,000,000 Five-Year Competitive Advance and Revolving Credit Facility Agreement dated March 27, 1998 with The Chase Manhattan Bank, as Administrative Agent, or the revolving credit facility replacing such agreement. All payments of interest shall be calculated on the basis of actual number of days elapsed in a calendar year of 365 or 366 days, as the case may be. 4. Borrower may prepay at any time all or any party of the unpaid principal advances. 5. All payments shall be made in lawful currency of the United Sates of America in immediately available funds. All amounts payable under this Note shall be paid when due without offset, defense, or counterclaim of any kind, nature, or description. All payments shall be applied first to accrued but unpaid interest and then to unpaid principal balances. If any payment of interest or principal hereunder becomes due and payable on a Saturday, Sunday, or holiday when banks are closed, such payment shall be made on the next business day and interest shall accrue at the applicable rate to the payment date. 6. The occurrence of any of the following events shall be deemed an "Event of Default" under this Note: (a) the failure of Debtor to pay when due any principal, interest, or other charges payable under this Note; (b) Debtor makes an assignment for
the benefit of creditors; (c) attachment or garnishment proceedings are commenced against Debtor; (e) a receiver, trustee or liquidator is appointed over or execution levied upon any property of Debtor; (f) proceedings are instituted by or against Debtor under bankruptcy, relief of debtors, including, without limitation, the United States Bankruptcy Code. 7. Upon the occurrence of an Event of Default, the Payee may immediately, at its option, pursue any one or more of the following remedies: (a) declare the entire unpaid principal balance of this Note, together with all accrued interest and any other charges or amounts payable hereunder immediately due and payable, regardless of the maturity date, without presentment, demand, or notice of any kind, all of which are expressly waived; (b) pursue any other rights and remedies of Payee under applicable law; or (c) offset against any amounts payable under this Note any other debts or obligations of the Payee to Debtor, whether or not then due. The remedies provided in this Note are cumulative and not mutually exclusive. Such remedies may be exercised and enforced alternatively, successively, and concurrently, at the sole discretion of the Payee, as often and whenever an occasion may arise. 8. After maturity of any amount payable under this Note, as to such amount, and from and after the occurrence of an Event of Default, as to the unpaid principal balance of this Note, all accrued interest payable under this Note from the date due, and all other charges payable under this Note, interest shall accrue at a rate equal to the then applicable interest rate plus two percent (the Maturity Rate). 9. In no event shall the total of all amounts payable hereunder, whether of interest or of other charges which may or might be characterized as interest, exceed the maximum rate or amount permitted to be charged under applicable law. If Payee receives any payment that is or would be in excess of the interest or other charge permitted to be charged under applicable law, the portion of the payment which is in excess of the permissible amount shall have been, and shall be deemed to have been, a payment in reduction of the principal balance of this Note or, if such portion exceeds the unpaid principal balance, the excess shall be refunded to Debtor. 10. Debtor and all endorsers, sureties, guarantors, and other persons who are or may become liable for payment of all or any part of the obligations evidenced by this Note agree jointly and severally to pay on demand all costs, charges, and expenses, including attorneys' fees, to the extent permitted by law, which may be incurred by the Payee for the collection of any sums due hereunder or for defending or enforcing any of the Debtor's rights hereunder, together with interest on such costs from the date incurred by the Payee until paid at the Maturity Rate. 11. Debtor, for itself and for all endorsers, sureties, guarantors, and other persons who now are or who may become liable for payment of all or any part of the obligations evidenced by this Note, jointly and severally and irrevocably hereby (a) waives demand for payment, protest, notice of dishonor or nonpayment, valuation and appraisement, notice of protest, and presentment for payment and any and all other
notices and demands whatsoever and any and all delays or lack of diligence in the collection thereof; (b) waives all rights to have the indebtedness and other obligations evidenced by or arising under this Note marshaled; and (c) consents and agrees to and waives ay notice of any and all renewals, extension, modifications or indulgences pertaining to the terms of this Note, and to any and all releases or substitutions of any party liable for the payment of, or any security for the payment of, any sums due under this Note. Any such renewal, extension, modification, release, or substitution may be made without notice to any such party and without discharging any such party's liability hereunder. 12. No delay, failure or forbearance on the part of Payee in exercising any right, power, privilege or remedy hereunder shall affect such right, power or remedy or be deemed a waiver of the same or any part thereof; nor shall any single or partial exercise thereof or any failure to exercise the same in any instance preclude any further or future exercise thereof or the exercise of any other right, power, privilege or remedy hereunder. 13. All notices or other communications required or permitted to be given pursuant to the provisions of this Note shall be deemed to have been duly given or make: if by hand, immediately upon delivery; if by telex, immediately upon sending; if by express mail or any other public, semi-public, or private overnight delivery service, one (1) day after dispatch; and if mailed by certified mail, postage prepaid and return receipt requested, one (1) day after deposit in the mail. All such notices and communications shall be given to the parties at their respective addresses set forth in this Note, or to such other addresses as either party may designate by notice in accordance with the terms of this Section. 14. This Note shall be governed by and construed in accordance with the laws of the State of Kansas, except to the extent that federal usury law may be applicable. The terms of this Note are severable. If any provision, or the application of any provision, shall be declared invalid or unenforceable, the remaining provision and all other applications of such provisions shall remain in full force and effect, and in no way shall be impaired. 14. This Note and every covenant and agreement herein contained shall be jointly and severally binding upon Debtor and Debtor's heirs, successors and assigns and shall inure to the benefit of the Payee and its successors and assigns. 15. Time is of the essence of this Note. IN WITNESS WHEREOF, this Note has been executed on the day and year first above written.
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, ---------------------------------------------------------- 2001 2000 1999 1998 1997 --------- -------- --------- -------- ---------- Earnings (losses) from continuing operations (a) ............. $(159,943) $120,273 $ (48,798) $ 58,088 $ 872,739 --------- -------- --------- -------- ---------- Fixed Charges: Interest expense ...................... 259,474 298,960 294,104 226,120 193,225 Interest on Corporate-owned Life Insurance Borrowings ......... 50,408 45,634 36,908 38,236 36,167 Interest Applicable to Rentals ........................... 28,908 28,898 34,252 32,796 34,514 --------- -------- --------- -------- ---------- Total Fixed Charges .......... 338,790 373,492 365,264 297,152 263,906 --------- -------- --------- -------- ---------- Distributed income of equity investees ............................. 2,769 2,686 3,728 3,812 -- Preferred and Preference Dividend Requirements: Preferred and Preference Dividends (e) ..................... 895 1,129 1,129 3,591 4,919 Income Tax Required ................... 591 746 746 1,095 3,770 --------- -------- --------- -------- ---------- Total Preferred and Preference Dividend Requirements ............ 1,486 1,875 1,875 4,686 8,689 --------- -------- --------- -------- ---------- Total Fixed Charges and Preferred and Preference Dividend Requirements .......................... 340,276 375,367 367,139 301,838 272,595 --------- -------- --------- -------- ---------- Earnings (b) ................................. $ 181,616 $496,451 $ 320,194 $359,052 $1,136,645 ========= ======== ========= ======== ========== Ratio of Earnings to Fixed Charges ............................... (c) 1.33 (c) 1.21 4.31 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements ................. (d) 1.32 (d) 1.19 4.17 (a) Earnings from continuing operations consists of earnings or loss before income taxes adjusted for minority interest and undistributed earnings from equity investees. (b) Earnings are deemed to consist of earnings (losses) from continuing operations, 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. (c) The company's earnings were deficient to cover fixed charges by $157.2 million and $45.1 million at December 31, 2001 and 1999, respectively. (d) The company's earnings were deficient to cover fixed charges and preferred and preference dividend requirements.by $158.7 million and $46.9 million at December 31, 2001 and 1999, respectively. (e) 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.
Exhibit 21 WESTERN RESOURCES, INC. Subsidiaries of the Registrant Subsidiary State of Incorporation Date Incorporated ---------- ---------------------- ----------------- 1) Kansas Gas and Electric Company Kansas October 9, 1990 2) Westar Industries, Inc. Kansas October 8, 1990 3) Protection One, Inc. Delaware June 21, 1991
EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into the Company's previously filed Registration Statements File 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. 333-93355, 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, March 27, 2002
Exhibit 99(c) March 27, 2002 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Arthur Andersen LLP has represented to us that the audit of Western Resources, Inc. for the year ended December 31, 2001, was subject to Arthur Andersen's quality control system for the U.S. accounting and auditing practice to provide reasonable assurance that the engagement was conducted in compliance with professional standards and that there was appropriate continuity of Arthur Andersen personnel working on audits and availability of national office consultation, and the availability of personnel at foreign affiliates of Arthur Andersen to conduct the relevant portions of the audit. WESTERN RESOURCES, INC. Date: March 27, 2002 By: /s/ PAUL R. GEIST ------------------------------ ------------------------------- Paul R. Geist Senior Vice President, Chief Financial Officer and Treasurer