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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2002

OR

For the transition period from                 to                  

Commission File Number 1-3523

Westar Energy, Inc.

(Exact name of registrant as specified in its charter)

          818 South Kansas Avenue, Topeka, Kansas 66612                (785) 575-630              

(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:

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.    ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $1,095,919,835 at June 28, 2002.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

DOCUMENTS INCORPORATED BY REFERENCE:

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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,” “target,” “expect,” “pro forma,” “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; accounting matters; possible corporate restructurings, mergers, acquisitions and dispositions; the sale of assets proposed in our Debt Reduction and Restructuring Plan filed with the Kansas Corporation Commission on February 6, 2003; compliance with debt and other restrictive covenants; interest and dividends; Protection One, Inc.’s financial condition and its impact on our consolidated results; possible future impairment charges; environmental matters; nuclear operations; 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 or re-regulation; regulated and competitive markets; ongoing municipal, state and federal activities; economic conditions; changes in accounting requirements and other accounting matters; changing weather; rate and other regulatory matters, including the impact of the November 8, 2002 and December 23, 2002 orders issued by the Kansas Corporation Commission requiring debt reduction; amendments or revisions to our Debt Reduction and Restructuring Plan filed with the Kansas Corporation Commission; the impact of changes and downturns in the energy industry and the market for trading wholesale electricity; the sale of our interests in ONEOK, Inc., Protection One, Inc., and Protection One Europe; the federal grand jury subpoena by the United States Attorney’s Office requesting certain information; the Securities and Exchange Commission’s review of our consolidated financial statements; the subpoena received from the Federal Energy Regulatory Commission seeking information on power trades with Cleco Corporation and its affiliates and on other power marketing transactions; political, legislative and regulatory developments; regulatory, legislative and judicial actions; the impact of the purported shareholder and employee class action lawsuits filed against us; the impact of changes in interest rates generally and, specifically, changes in the London Interbank offer rate (LIBOR) on the fair value of our swap transactions; changes in the 10-year United States treasury rates and the corresponding impact on the fair value of our call option; homeland security considerations; ongoing impairment tests; coal, natural gas and oil prices; 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. This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter. 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 except as required by applicable laws or regulations.

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PART I

ITEM 1. BUSINESS

GENERAL

Westar Energy, Inc., a Kansas corporation incorporated in 1924, operates the largest electric utility in Kansas and owns interests in monitored security businesses and other investments. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” or similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc. alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 647,000 customers in Kansas. We also provide monitored security services to over 1.1 million customers in the United States and Europe. ONEOK, Inc. (ONEOK), in which we presently own an approximate 27.5% interest (we owned an approximate 45% interest at December 31, 2002; see “— Changes in ONEOK Ownership” below), provides natural gas transmission and distribution services to approximately 1.9 million customers in Kansas, Oklahoma and Texas. Our corporate headquarters are located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Westar Energy and Kansas Gas and Electric Company (KGE), a wholly owned subsidiary, provide rate regulated electric service. KGE owns 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek), our nuclear powered generating facility.

Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owns our interests in Protection One, Inc. (Protection One), Protection One Europe, ONEOK and our other non-utility businesses. Protection One, a publicly traded, approximately 88%-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 an approximate 99.8% interest.

SIGNIFICANT BUSINESS DEVELOPMENTS

Overview

A number of significant developments have impacted us and our business operations since January 2002.

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New Chief Executive Officer and Senior Management Team

James S. Haines, Jr., joined us in December 2002 as our chief executive officer and president and a member of the board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with us and our affiliates. Mr. Wittig had been on administrative leave without pay since November 7, 2002 as a result of his indictment by a federal grand jury in Topeka, Kansas, for actions arising from his personal dealings.

Mr. Haines added new members to our senior management team, including William B. Moore as executive vice president and chief operating officer, and Mark A. Ruelle as executive vice president and chief financial officer. All of these officers were previously employed with us and have a strong background in the electric utility business. Douglas T. Lake, our executive vice president and chief strategic officer, resigned as a member of the board of directors and was placed on unpaid leave from all of his other positions with us and our affiliates on December 6, 2002.

See Note 35 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about our potential liabilities to Mr. Wittig and Mr. Lake.

KCC Orders and Debt Reduction and Restructuring Plan

On February 6, 2003, we filed the Debt Reduction Plan with the KCC outlining our plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of our non-utility assets, including our interests in Protection One, Protection One Europe and ONEOK. As part of the Debt Reduction Plan, the first quarter 2003 dividend on our common stock was reduced 37% to $0.19 per share. In addition, the Debt Reduction Plan contemplates the potential issuance of additional Westar Energy equity, if needed to further reduce debt following the disposition of all material non-utility assets. On February 10, 2003, the KCC issued an order in which it stated that the Debt Reduction Plan appears to make a good-faith effort to address the concerns expressed in the KCC’s prior orders and that the KCC needed additional time to review the Debt Reduction Plan prior to addressing other issues. The KCC also stayed the requirement of a December 23, 2002 order that we form a utility-only subsidiary for our former KPL electric utility division (KPL) no later than August 1, 2003.

The Debt Reduction Plan replaced a previous financial plan to which we devoted extensive efforts throughout 2002 to obtain KCC approval. This plan contemplated the sale of Westar Industries common stock in a rights offering. We refer you to our Annual Report on Form 10-K for the year ended December 31, 2001 and subsequent Quarterly Reports on Form 10-Q for further information on this financial plan and related KCC orders. The KCC rejected this plan on November 8, 2002 and issued an order that directed us to file a new financial plan, to reverse specified intercompany transactions, to reduce debt by $100 million annually in each of the next two years from internally generated cash flow, and to restructure our organizational structure so that KPL would be placed in a separate subsidiary with the amount of debt held by the utility not exceeding $1.47 billion. The order further established standstill protections requiring that we seek KCC approval before we enter into certain transactions with a non-utility affiliate. Following our filing of a motion for reconsideration and clarification of this order, the KCC

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issued an order on December 23, 2002 directing that no later than August 1, 2003, KPL be held within a separate utility-only subsidiary and that the consolidated debt for all of our utility businesses not exceed $1.67 billion.

The standstill provisions of the December 23, 2002 KCC order potentially could have had a material adverse impact on Protection One. These standstill provisions are described in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.” On March 11, 2003, the KCC issued an order permitting us to make the payment due to Protection One in 2003 under a tax sharing agreement and to continue making loans to Protection One under a revolving credit facility. In addition, the order permitted us to reimburse Protection One approximately $4.4 million for information technology and aviation services, subject to certain conditions.

The KCC staff and other parties to the KCC docket considering the Debt Reduction Plan have filed comments on the Debt Reduction Plan. The KCC has not yet established a procedural schedule for considering the Debt Reduction Plan and the related comments. We are unable to predict what action the KCC will take with respect to the Debt Reduction Plan.

The KCC Orders dated November 8, 2002, December 23, 2002, February 10, 2003 and March 11, 2003 and the Debt Reduction Plan are exhibits to this Annual Report on Form 10-K. All of such exhibits are incorporated by reference herein. All of the documents concerning these matters, including the KCC Orders, can also be reviewed at the website of the KCC at www.kcc.state.ks.us (the website information is not incorporated herein or otherwise made a part of this Annual Report on Form 10-K). We refer you to these documents for further information concerning these matters.

Changes in ONEOK Ownership

On February 5, 2003, ONEOK repurchased from Westar Industries 9,038,755 shares of its Series A Convertible Preferred Stock, which were convertible into 18,077,511 shares of common stock. We received $300 million as a result of this sale, which was previously approved by the KCC. We anticipate using all or a portion of the net proceeds to repurchase or provide for the repayment of all of the putable/callable notes and a portion of our 6.875% senior unsecured notes.

Westar Industries also exchanged its remaining shares of Series A Convertible Preferred Stock for 21,815,386 new shares of ONEOK’s Series D Convertible Preferred Stock. ONEOK has agreed to file a shelf registration statement covering the Series D Convertible Preferred and common stock held by Westar Industries. Future sales will be subject to various conditions including the effectiveness of such registration, the required waiver or expiration of a 180-day lock-up period ending on July 22, 2003, and future market conditions. As of March 14, 2003, Westar Industries holds an approximate 27.5% ownership interest in ONEOK, assuming conversion of the Series D Convertible Preferred Stock.

In 2002 and prior periods, we accounted for our ONEOK common stock investment under the equity method of accounting. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and mark to market its fair value through other comprehensive income. We will begin accounting for our ONEOK Series D Convertible Preferred Stock investment under this method if and when a public market for these securities develops.

Sale of Protection One and Protection One Europe

On January 13, 2003, we announced that our board of directors authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe. The Debt Reduction Plan provides for the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. As a result, these operations were classified as discontinued operations during the first quarter of 2003 pursuant to the provisions of SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.”

As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount, which could be material, by which our basis exceeds the estimated fair value.

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We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.

Ongoing Investigations

Grand Jury Subpoena

On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and the company in general. We are providing information in response to these requests and are fully cooperating in the investigation. We have not been informed that we are a target of the investigation. We are unable to predict the ultimate outcome of the investigation or its impact on us.

Securities and Exchange Commission Inquiry

On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these matters and other matters within the scope of the grand jury investigation. We are unable to predict the ultimate outcome of the inquiry or its impact on us.

Special Committee Investigation

Our board of directors appointed a Special Committee of directors to investigate management matters and matters that are the subject of the grand jury investigation and SEC inquiry. The Special Committee retained counsel and other advisors. The Special Committee investigation has been completed and has not resulted in adjustments to our consolidated financial statements.

FERC Subpoena

On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation (Cleco) and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries.

We have provided information to FERC in response to the subpoena. We believe that our participation in these transactions did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation. See Note 19 of the Notes to Consolidated Financial Statements, “Ongoing Investigations — FERC Subpoena,” for additional information.

Call Option

In August 1998, we entered into a call option with an investment bank related to the issuance of $400 million of our putable/callable notes. This call option is required to be settled by August 2003 through either a cash payment or a remarketing or refinancing of the putable/callable notes. The ultimate value of the call option will be based on the difference between the 10-year United States treasury rate on August 12, 2003 and 5.44%. If the 10-year United States treasury rate on August 12, 2003 is less than 5.44%, we will have a liability to the investment bank at that time. At December 31, 2002, our potential liability under the call option was $62.2 million. Based on the 10-year forward treasury rate on March 14, 2003 of 3.91%, we would be obligated to make a cash payment of approximately $69.1 million to settle the call option if we did not remarket or refinance the notes. The amount of

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our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. If settled through a remarketing or refinancing, any liability related to the call option will be amortized as a credit to interest expense over the term of the new debt. The investment bank will price the notes to yield a market premium adequate to allow the investment bank to retain proceeds equal to the fair value of the call option at settlement.

At the time of issuance of the notes in 1998, we were not required by generally accepted accounting principles (GAAP) to account separately for the call option. However, when we began retiring these notes as a part of our overall debt reduction strategy, the portion of the call option associated with the retired notes became a free-standing option required to be treated as a derivative instrument under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). In addition, under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our balance sheet reflects the current fair value of the free standing portion of the call option. For 2002, we recognized a loss of $10.1 million, net of $6.7 million tax benefit, related to the fair value of the call option associated with the putable/callable notes at the time the notes were retired. This loss is included in our consolidated statements of income as part of the gain on extinguishment of debt line item of other income. For 2002, we also recorded an additional non-cash charge of $13.6 million, net of $9.0 million tax benefit, to reflect mark to market changes in the fair value of the call option associated with the retired notes. This charge is reflected in the other line item of other income in our consolidated statements of income. In total, the loss recorded related to the fair value of the call option for the year ended December 31, 2002 was $23.7 million, net of $15.7 million tax benefit.

We intend to repurchase or provide for the repayment of the putable/callable notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. From January 1, 2003 through March 14, 2003, we purchased $35.3 million face value of our putable/callable notes. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.

Impairment Charges

Effective January 1, 2002, we adopted SFAS No. 142, “Accounting for Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” As a result of implementing the new standards, we recorded a charge for the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.

In addition, in the fourth quarter of 2002 we recorded a $79.7 million impairment charge, net of tax benefit and minority interests, to reflect the additional impairment of all remaining goodwill of Protection One’s North America segment. We also recorded a $36 million impairment charge to reflect the impairment of all remaining goodwill at Protection One Europe. These accounting standards, the related charges and other related information are discussed in Note 23 of the Notes to Consolidated Financial Statements, “Impairment Charges.”

Work Force Reductions

During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We recorded a net charge of approximately $21.7 million in 2002 related to this program. We have replaced and may continue to replace some of these employees. For additional information, see Note 29 of the Notes to Consolidated Financial Statements, “Work Force Reductions.”

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. Through December 31, 2002, we incurred $19.3 million for restoration costs, a portion of which was capitalized. We have deferred and recorded as a regulatory asset on our December 31, 2002 consolidated balance sheet restoration costs of approximately $15.0 million. We have received an accounting authority order from the KCC that allows us to accumulate and defer for potential future recovery all operating and carrying costs related to storm restoration.

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ELECTRIC UTILITY OPERATIONS

General

We supply electric energy at retail to approximately 647,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We classify our customers as residential, commercial and industrial as defined in our tariffs. We also supply electric energy at wholesale to the electric distribution systems of 62 Kansas cities and four 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 that purchase and sell electricity in areas outside our historical service territory.

Our electric sales for the three years ended December 31 were as follows:

The following tables show changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity we generate, for the three years ended December 31. No sales volumes are shown for network integration or power marketing because these activities are not related to electricity we generate.

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Generation Capacity

We have 5,929 megawatts (MW) of generating capacity. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.

Our aggregate 2002 peak system net load of 4,469 MW occurred on July 26, 2002. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 24% above 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 do not anticipate needing additional generating capacity through 2005.

We have agreed to provide generating capacity to other utilities for certain periods as set forth below:

Fossil Fuel Generation

Fuel Mix

Based on the quantity of heat produced during the generation of electricity (MMBtu), the 2002 actual fuel mix was 81% coal, 14% nuclear and 5% gas, oil or diesel fuel. We expect a similar fuel mix in 2003. Our fuel mix fluctuates with the operation of the nuclear-powered Wolf Creek as discussed below under “— Nuclear Generation,” fuel costs, plant availability, customer demand and the cost and availability of wholesale market power.

Coal

Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center (JEC) have an aggregate capacity of 1,855 MW (our 84% share). We have a long-term coal supply contract with Amax Coal West, Inc., a

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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 contract also contains a mechanism for repricing quantities received above the minimum annual delivery quantity. The price for these additional quantities is recalculated every five years, with 2003 being the first year affected, to provide a fixed price at current market prices. Current market prices are higher than those that have been in effect since inception of the contract, which will increase the cost of coal we receive during 2003 over the cost of coal received in 2002. Based on our 2003 budget of JEC coal we plan to burn during 2003, we anticipate our delivered cost of coal will increase approximately $4.0 million.

The coal supplied during 2002 was surface mined and had an average Btu content of approximately 8,423 Btu per pound and an average sulfur content of 0.46 lbs/MMBtu (see “— Environmental Matters”). The average delivered cost of coal burned at JEC during 2002 was approximately $1.12 per MMBtu, or $18.87 per ton.

Coal is transported from Wyoming under a long-term rail transportation contract with the Burlington Northern Santa Fe (BNSF) and Union Pacific railroads, with a term continuing through December 31, 2013.

LaCygne Generating Station: The two coal-fired units at LaCygne Generating Station (LaCygne) 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, 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 fixed price contracts through 2005 and is transported under KCPL’s Omnibus Rail Transportation Agreement with the BNSF and Kansas City Southern Railroad through December 31, 2010. During 2003, any coal not supplied under the terms of these contracts will be obtained through spot market purchases. 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 2002 had an average Btu content of approximately 8,584 Btu per pound and an average sulfur content of 0.78 lbs/MMBtu. During 2002, the average delivered cost of all coal burned at LaCygne 1 was approximately $0.91 per MMBtu, or $16.06 per ton. The average delivered cost of coal burned at LaCygne 2 was approximately $0.77 per MMBtu, or $13.18 per ton.

Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 795 MW. In 2002, we obtained coal from Wyoming, which had an average Btu content of approximately 8,777 Btu per pound and an average sulfur content of 0.41 lbs/MMBtu. During 2002, the average delivered cost of all coal burned in the Lawrence units was approximately $1.09 per MMBtu, or $19.11 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.10 per MMBtu, or $19.28 per ton.

The coal is transported from Wyoming by the BNSF railroad under a contract ending in December 2004. We have Wyoming coal under contract to support the anticipated operation of these units through the end of 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 supplied pursuant to these contracts and that we would be able to make transportation arrangements for such coal. 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. Since the majority of our coal needs are met through long-term contracts as discussed above, we do not anticipate being materially impacted by price changes in the coal spot market.

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.

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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 a flexible natural gas supply as necessary to meet operational needs. During 2002, we purchased 8,885,567 MMBtu of natural gas on the spot market for a total cost of $34.2 million. Natural gas accounted for approximately 3% of our total fuel burned during 2002.

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. The hedged period ends in July 2004. Thereafter, if gas prices are higher than the amount we are able to recover through our retail rates, we may be exposed to the increased gas cost and our exposure could be material. We may be able to reduce our exposure due to our ability to use other fuel types. To recover increased gas costs in excess of the cost included in retail rates, we would have to make a rate filing with the KCC or request a recovery mechanism through the KCC, which could be denied in whole or in part. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Natural gas transportation for Abilene and Hutchinson Energy Centers is maintained with Kansas Gas Service Company, a division of ONEOK, under a contract that expires April 30, 2004, which we anticipate renewing in the future. We meet a portion of our natural gas transportation requirements for Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. All of the natural gas transportation requirements for the State Line facility are met through a firm natural gas transportation agreement with Southern Star Central Pipeline. The firm transportation agreements that serve Gordon Evans, Murray Gill, Lawrence and Tecumseh Energy Centers extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016.

Oil

Most of our natural gas generating facilities have the capability to switch to oil once the facilities have been started with gas. We use oil as an alternate fuel when economical or when interruptions to natural gas supply make it necessary. Over the past few years, we have been able to sell more power at wholesale during the winter months when oil is typically more economical than natural gas. Oil accounted for approximately 2% of our total fuel burned during 2002.

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 fuel switching needs to facilitate economic dispatch of power, for emergency requirements and to 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 7A. Quantitative and Qualitative Disclosures About Market Risk” for further information.

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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.

Purchased Power

At times, we purchase power to meet the energy needs of our wholesale customers and to meet the requirements of our retail native load customers (end-use customers within our service territory). Factors that could cause us to purchase power for retail native load customers include generating plant outages, extreme weather conditions, growth, and other factors associated with supplying full requirements electricity. 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.

Nuclear Generation

Fuel Supply

The owners of Wolf Creek have on hand or under contract 100% of their uranium and uranium conversion needs for 2003 and 76% of the uranium and uranium conversion required for operation of Wolf Creek through March 2008. 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 2003 and 80% of the uranium enrichment required to operate Wolf Creek through March 2008. The balance of Wolf Creek’s enrichment needs is expected to be obtained through spot market and contract purchases.

All uranium, uranium conversion and uranium enrichment arrangements have been entered into in the ordinary course of business, and Wolf Creek is not substantially dependent upon these agreements. Despite contraction and consolidation in the supply sector for these commodities and services, Wolf Creek’s management believes there are other supplies available to replace, if necessary, these contracts. In the event these contracts were required to be replaced, Wolf Creek’s management does not anticipate a substantial disruption of Wolf Creek’s operations.

Nuclear fuel is amortized to cost of sales based on the quantity of heat produced for the generation of electricity.

Radioactive Waste Disposal

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

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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.

On February 14, 2002, the Secretary of Energy submitted to the President a recommendation for approval of the Yucca Mountain site in Nevada for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. In July 2002, the President signed a resolution approving the Yucca Mountain site after receiving the approval of this site from the U.S. Senate and House of Representatives. This action allows the DOE to apply to the Nuclear Regulatory Commission (NRC) to license the project. The DOE expects that this facility will open in 2010. However, the opening of the Yucca Mountain site could be delayed due to litigation and other issues related to the site as a permanent repository for spent nuclear fuel.

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 preconstruction financing for this project. Our net investment in the Compact is approximately $7.4 million. This amount constitutes about 7.6% of all preconstruction financing provided to the Compact.

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 preconstruction 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), which is 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. The U.S. District Court has since dismissed the utilities’ and US Ecology’s claims against Nebraska and its officials, but on September 30, 2002, the court entered a $151.4 million judgment, about one-third of which constitutes prejudgment interest, in favor of the Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. In late 2002, Nebraska appealed that decision to the 8th Circuit U.S. Court of Appeals, where the case is pending.

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. 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 that permits operations during every third calendar year without interruption for a refueling outage. Wolf Creek was shut down for 36 days for its 12th scheduled refueling and maintenance outage, which began on March 23, 2002 and ended on April 27, 2002. During the outage, electric demand was met primarily by our fossil-fueled generating units and by purchased power. Wolf Creek operated the entire year of 2001 without any refueling outages. Wolf Creek is scheduled to be taken off-line in October 2003 for its 13th refueling and maintenance outage.

An extended shutdown 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, the NRC could impose an unscheduled plant shutdown due to security or other concerns.

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Security

We have increased the level of security measures at our generation facility sites and various offices, due in part to nationwide concerns about homeland security. These measures include, but are not limited to, increased security personnel, use of armed guard services, patrolling of company property, restricting access to our properties and implementing emergency training and response procedures.

Wolf Creek’s management has increased both voluntary and federally mandated security measures at Wolf Creek. The NRC has required nuclear power plants to be operated at the highest level of security since September 11, 2001. The measures implemented at Wolf Creek include, but are not limited to, increased guard service, no unscheduled 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 has complied with and intends to continue to comply with these requirements.

Competition and Deregulation

Electric utilities have historically operated in a rate-regulated environment. FERC, the Federal regulatory agency having jurisdiction over our wholesale rates and transmission services, and other utilities have initiated steps that are expected to result in a more competitive environment for utility services in the wholesale market. The Kansas Legislature and the KCC took no action on deregulation in 2002 or 2001 and no action is expected to be taken in the near future.

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. Our rates range from approximately 19% to 25% below the national average for retail customers based on a comparison to a U.S. average obtained from Edison Electric Institute for Winter 2002. Because of these rates, we expect to retain a substantial part of our current volume of sales in a competitive environment. However, 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.” See Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted FERC to order electric utilities to allow third parties to use their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating open and more competitive markets in bulk power.

We and all other electric utilities with intrastate transmission facilities operate under FERC regulated open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services, at the same rates, that the utilities provide themselves. We are a member of the Southwest Power Pool (SPP), a regional division of the North American Electric Reliability Council. After FERC rejected several attempts by the SPP to gain RTO status, the SPP and the Midwest Independent System Operator (MISO) agreed in October 2001 to consolidate and form an RTO. On May 30, 2002, FERC approved the planned merger. On November 4, 2002, MISO and SPP filed a revised consolidated open-access transmission tariff as required by the merger agreement. On March 19, 2003, the SPP’s board of directors voted to terminate the proposed merger with MISO, although both organizations have not precluded a future consolidation. We anticipate that FERC Order No. 2000 and our continued participation in the SPP will not have a material effect on our operations.

Network Integration Transmission Service

Effective January 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. This provides a cost-effective way for us to participate in a broader market of generation resources with the possibility of lower transmission costs. This tariff provides for a zonal rate structure, whereby transmission customers pay a pro rata share, in the form of a reservation charge, for the use of the facilities

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for each transmission owner that serves them. As a result, the SPP has operational control over our transmission system, although we still own our transmission assets and maintain responsibility for dispatching, maintenance and storm restoration.

Currently, all revenues collected within a zone are allocated back to the transmission owner serving the zone. Since we are a transmission provider for our zone and are currently the only transmission customer taking service from that zone, we are currently being assessed 100% of the zonal costs and receiving all of the costs back as revenue, less servicing fees. In 2002, these network integration transmission costs were approximately $65.9 million, and the associated revenues were approximately $60.1 million, for a net expense of approximately $5.8 million. The revenues received are reflected in electric operating revenues, and the related charges are expensed.

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, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of some 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 the Public Utility Holding Company Act of 1935 from all provisions of that Act, except Section 9(a)(2), which relates to the acquisition of the securities of other utilities.

Fuel and purchased power costs are recovered in retail rates at a fixed level. Therefore, to recover fuel and purchased power costs in excess of the costs included in retail rates, we would have to make a rate filing with the KCC, which could be denied in whole or in part. Any increase in fuel and purchased power costs over the costs recovered through rates would reduce our earnings if not offset by sales or other cost reductions. For additional information regarding commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

On November 27, 2000, Westar Energy 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 Westar Energy’s rates.

On August 9, 2001, Westar Energy 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 Westar Energy’s rates 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. On April 8, 2002, we filed a petition for review of the decision of the Court of Appeals with the Kansas Supreme Court. Our petition for review was denied on June 12, 2002.

Additional information with respect to rate matters and regulation is set forth in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.”

Environmental Matters

General

We currently hold all federal and state environmental approvals required for the operation of all of our generating units. We believe we are currently in substantial compliance with all air quality regulations (including those pertaining to particulate matter, sulfur dioxide (SO2) and nitrogen oxide (NOx)) promulgated by the State of Kansas and the Environmental Protection Agency (EPA).

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The JEC and LaCygne 2 units have met: (1) the federal SO2 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 SO2 and particulate matter emission reduction capability when needed to meet permit limits.

The Kansas Department of Health and Environment regulations applicable to our other generating facilities prohibit the emission of more than 3.0 pounds of SO2 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.

Because of the strong demand for generation in 2002, we consumed more SO2 allowances than were allocated to us by the EPA. We made up the shortfall by utilizing allowances we had previously procured in the open market. In anticipation of another strong year in generation, we will be actively pursuing the purchase of additional SO2 allowances for 2003, which could approximate $3.0 million in additional costs.

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 some 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 SO2 and NOx 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.

EPA New Source Review

The EPA is conducting an enforcement initiative at a number of coal-fired power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA has requested information from us under Section 114(a) of the Clean Air Act (Section 114). A Section 114 information request requires us to provide responses to specific EPA questions regarding certain projects and maintenance activities that the EPA believes may have violated the New Source Performance Standard and New Source Review requirements of the Clean Air Act. The EPA contends that power plants are required to update emission controls at the time of major maintenance or capital activity. We believe that maintenance and capital activities performed at our power plants are generally routine in nature and are typical for the industry. We are complying with this information request, but cannot predict the outcome of this investigation at this time. Should the EPA determine to take action, the resulting additional costs to comply could be material. We would expect to seek recovery through rates of any settlement amounts.

The EPA has initiated civil enforcement actions against other unaffiliated utilities as part of its initiative. Settlement agreements entered into in connection with some of these actions have provided for expenditures to be made over extended time periods.

Additional information with respect to Environmental Matters is discussed in Note 17 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies,” and such information is incorporated herein by reference.

MONITORED SERVICES OPERATIONS

General

We provide property monitoring services through Protection One and Protection One Europe to approximately 1.1 million customers in the United States and approximately 55,000 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, the United States customers are primarily in the residential market and the European customers are primarily in the commercial market.

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Proposed Dispositions

The Debt Reduction Plan contemplates the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. Consistent with the Debt Reduction Plan, our board of directors has authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe and we have retained financial advisors to assist with the possible sales. A special committee comprosed of independent directors of Protection One’s board of directors has been formed and the committee has also retained a financial advisor. As a result of these decisions, these operations were classified as discontinued operations during the first quarter of 2003 under the provisions of SFAS No. 144.

As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount, which could be material, by which our basis exceeds the estimated fair value.

We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.

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 at customers’ premises designed to detect or react to various occurrences or conditions, such as intrusion or the presence of fire or smoke. Existing alarm monitoring customer contracts generally have initial terms ranging from two to 10 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. Since 2002, most new single family residential customers have been entering into contracts with initial terms of three years, and, for most new commercial customers, the initial term is five years.

Protection One provides monitoring services from four monitoring facilities in the United States. Protection One Europe provides monitoring services from facilities in Paris and Vitrolles, France. See “Item 2. Properties” for further information.

In 2001 and 2002, Protection One completed the installation of a common technology platform referred to as MAS^®, or Monitored Automation Systems, that combines the customer service, monitoring, billing and collection functions into a single system. The conversion to MAS^® has enabled Protection One to consolidate monitoring facilities, resulting in operational efficiencies and cost savings. Approximately 98.5% of Protection One’s North America residential and commercial customer base is served by MAS^®.

Branch Operations

Protection One maintains approximately 60 service branches in the United States 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 31 sales branch offices in continental Europe, primarily in France.

Customer Acquisition Strategy

Protection One’s current customer acquisition strategy for the United States relies primarily on internally generated sales and a strategic alliance with BellSouth Telecommunications. The internal sales program generated 45,642 accounts in 2002 and 41,856 accounts in 2001. Protection One’s multifamily business markets its services and products primarily to developers, owners and managers of apartment complexes and other multifamily dwellings.

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Protection One Europe’s customer acquisition strategy relies primarily on internally generated sales. Protection One Europe uses an internal sales force of approximately 300 employees, who operate out of 31 branch locations in France, Germany and Belgium. 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.

Competition

The security alarm industry is highly competitive. In North America, only four alarm companies offer services across the United States, with the remainder being either large regional or small, privately held alarm companies. Based on total annual revenues in 2001, Protection One believes the top four alarm companies in North America are:

In continental Europe, a large number of small competitors and a few large regional competitors have recently been taking steps toward establishing a continental presence. The large regional competitors include the following companies:

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 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, giving competitors the ability to offer higher prices to purchase customer accounts than Protection One or Protection One Europe might be able or willing to offer. The effect of such competition may be to reduce the purchase opportunities available.

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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:

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 their business.

The alarm industry is also subject to requirements imposed by various insurance, approval, listing and standards organizations. Depending upon the type of customer served, the type of security service provided and the requirements of the applicable local governmental jurisdiction, adherence to the requirements and standards of such organizations is mandatory in some instances and voluntary in others.

Protection One’s advertising and sales practices are regulated in the United States by both the Federal Trade Commission and state consumer protection laws. In addition, certain administrative requirements and laws of the jurisdictions in which Protection One 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 and the obligation to provide purchasers of its alarm systems with certain rescission rights.

The alarm monitoring business utilizes wired and wireless telephones 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 Europe operates 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. Some 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 32 of the Notes to Consolidated Financial Statements, “Segments of Business.”

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GEOGRAPHIC INFORMATION

Geographic information is set forth in Note 32 of the Notes to Consolidated Financial Statements, “Segments of Business.”

EMPLOYEES

As of February 28, 2003, we had approximately 5,500 employees, including 1,900 utility employees and 3,600 employees of Protection One and Protection One Europe. Our current contract with the International Brotherhood of Electrical Workers extends through June 30, 2003. The contract covered approximately 1,100 utility employees as of February 28, 2003. We are currently discussing modifications to our existing contract with union representatives and expect these discussions to result in an agreement. We anticipate that formal bargaining will begin in April 2003 if these discussions are unsuccessful.

ACCESS TO COMPANY INFORMATION

We electronically file our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K with the SEC. The public may read and copy any of the reports that are filed with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically.

We make available, free of charge, through our website and by responding to requests addressed to our investor relations department, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These reports are available as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Our website address is www.wr.com. The information contained on our website is not part of this document.

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ITEM 2. PROPERTIES

ELECTRIC UTILITY FACILITIES

We own approximately 6,600 miles of transmission lines, approximately 27,000 miles of overhead distribution lines and approximately 3,000 miles of underground distribution lines.

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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 above facilities, although Protection One also leases office space for approximately 60 service branch offices and seven satellite branches in the United States and Protection One Europe leases offices for approximately 31 sales branch offices in continental Europe.

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ITEM 3. LEGAL PROCEEDINGS

Information on our legal proceedings is set forth in Notes 3, 18, 19 and 35 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Legal Proceedings,” “Ongoing Investigations,” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

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 2002.

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, 2003, there were 33,334 common shareholders of record. For information regarding quarterly common stock price ranges for 2002 and 2001, see Note 33 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

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 first be 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 business day 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 our common stock 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, regulation, including the KCC’s order requiring us to reduce our outstanding debt, competition and financial loan covenants. In February 2003, we declared a first-quarter 2003 dividend of $0.19 per share. Our Articles of Incorporation restrict 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 provide further information on these restrictions in Note 20 of the Notes to Consolidated Financial Statements, “Common Stock, Preferred Stock and Other Mandatorily Redeemable Securities.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock at the current rate.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Cash Requirements,” Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation” and Note 20, “Common Stock, Preferred Stock and Other Mandatorily Redeemable Securities,” included herein for additional information on dividends.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The information called for by the item relating to “Securities Authorized for Issuance Under Equity Compensation Plans” will be set forth under that heading in the Proxy Statement relating to the Annual Meeting of Shareholders to be held June 16, 2003, which will be filed with the Securities and Exchange Commission no later than April 30, 2003, and which is incorporated herein by reference. See also “Item 12. Security Ownership of Certain Beneficial Owners and Management.”

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ITEM 6. SELECTED FINANCIAL DATA

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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:

As you read Management’s Discussion and Analysis, please refer to our consolidated financial statements and the accompanying notes, which show our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Overview

A number of significant developments have impacted us and our business operations since January 2002.

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New Chief Executive Officer and Senior Management Team

James S. Haines, Jr., joined us in December 2002 as our chief executive officer and president and a member of the board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with us and our affiliates. Mr. Wittig had been on administrative leave without pay since November 7, 2002 as a result of his indictment by a federal grand jury in Topeka, Kansas, for actions arising from his personal dealings.

Mr. Haines added new members to our senior management team, including William B. Moore as executive vice president and chief operating officer, and Mark A. Ruelle as executive vice president and chief financial officer. All of these officers were previously employed with us and have a strong background in the electric utility business. Douglas T. Lake, our executive vice president and chief strategic officer, resigned as a member of the board of directors and was placed on unpaid leave from all of his other positions with us and our affiliates on December 6, 2002.

See Note 35 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about our potential liabilities to Mr. Wittig and Mr. Lake.

KCC Orders and Debt Reduction and Restructuring Plan

On February 6, 2003, we filed the Debt Reduction Plan with the KCC outlining our plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of our non-utility assets, including our interests in Protection One, Protection One Europe and ONEOK. As part of the Debt Reduction Plan, the first quarter 2003 dividend on our common stock was reduced 37% to $0.19 per share. In addition, the Debt Reduction Plan contemplates the potential issuance of additional Westar Energy equity, if needed to further reduce debt following the disposition of all material non-utility assets. On February 10, 2003, the KCC issued an order in which it stated that the Debt Reduction Plan appears to make a good-faith effort to address the concerns expressed in the KCC’s prior orders and that the KCC needed additional time to review the Debt Reduction Plan prior to addressing other issues. The KCC also stayed the requirement of a December 23, 2002 order that we form a utility-only subsidiary for our former KPL electric utility division (KPL) no later than August 1, 2003.

The Debt Reduction Plan replaced a previous financial plan to which we devoted extensive efforts throughout 2002 to obtain KCC approval. This plan contemplated the sale of Westar Industries common stock in a rights offering. We refer you to our Annual Report on Form 10-K for the year ended December 31, 2001 and subsequent Quarterly Reports on Form 10-Q for further information on this financial plan and related KCC orders. The KCC rejected this plan on November 8, 2002 and issued an order that directed us to file a new financial plan, to reverse specified intercompany transactions, to reduce debt by $100 million annually in each of the next two years from internally generated cash flow, and to restructure our organizational structure so that KPL would be placed in a separate subsidiary with the amount of debt held by the utility not exceeding $1.47 billion. The order further established standstill protections requiring that we seek KCC approval before we enter into certain transactions with a non-utility affiliate. Following our filing of a motion for reconsideration and clarification of this order, the KCC issued an order on December 23, 2002 directing that no later than August 1, 2003, KPL be held within a separate utility-only subsidiary and that the consolidated debt for all of our utility businesses not exceed $1.67 billion.

The standstill provisions of the December 23, 2002 KCC order potentially could have had a material adverse impact on Protection One. These standstill provisions are described in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.” On March 11, 2003, the KCC issued an order permitting us to

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make the payment due to Protection One in 2003 under a tax sharing agreement and to continue making loans to Protection One under a revolving credit facility. In addition, the order permitted us to reimburse Protection One approximately $4.4 million for information technology and aviation services, subject to certain conditions.

The KCC staff and other parties to the KCC docket considering the Debt Reduction Plan have filed comments on the Debt Reduction Plan. The KCC has not yet established a procedural schedule for considering the Debt Reduction Plan and the related comments. We are unable to predict what action the KCC will take with respect to the Debt Reduction Plan.

The KCC Orders dated November 8, 2002, December 23, 2002, February 10, 2003 and March 11, 2003 and the Debt Reduction Plan are exhibits to this Annual Report on Form 10-K. All of such exhibits are incorporated by reference herein. All of the documents concerning these matters, including the KCC Orders, can also be reviewed at the website of the KCC at www.kcc.state.ks.us (the website information is not incorporated herein or otherwise made a part of this Annual Report on Form 10-K). We refer you to these documents for further information concerning these matters.

Changes in ONEOK Ownership

On February 5, 2003, ONEOK repurchased from Westar Industries 9,038,755 shares of its Series A Convertible Preferred Stock, which were convertible into 18,077,511 shares of common stock. We received $300 million as a result of this sale, which was previously approved by the KCC. We anticipate using all or a portion of the net proceeds to repurchase or provide for the repayment of all of the putable/callable notes and a portion of our 6.875% senior unsecured notes.

Westar Industries also exchanged its remaining shares of Series A Convertible Preferred Stock for 21,815,386 new shares of ONEOK’s Series D Convertible Preferred Stock. ONEOK has agreed to file a shelf registration statement covering the Series D Convertible Preferred and common stock held by Westar Industries. Future sales will be subject to various conditions including the effectiveness of such registration, the required waiver or expiration of a 180-day lock-up period ending on July 22, 2003, and future market conditions. As of March 14, 2003, Westar Industries holds an approximate 27.5% ownership interest in ONEOK, assuming conversion of the Series D Convertible Preferred Stock.

In 2002 and prior periods, we accounted for our ONEOK common stock investment under the equity method of accounting. During 2003, we will account for our ONEOK common stock investment as an available-for-sale security under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and mark to market its fair value through other comprehensive income. We will begin accounting for our ONEOK Series D Convertible Preferred Stock investment under this method if and when a public market for these securities develops.

Sale of Protection One and Protection One Europe

On January 13, 2003, we announced that our board of directors authorized management to explore alternatives for disposing of our investments in Protection One and Protection One Europe. The Debt Reduction Plan provides for the sale of our interests in Protection One Europe with a targeted closing of mid-2003 and the sale of our interest in Protection One with a targeted closing by late 2003 or early 2004. As a result, these operations were classified as discontinued operations during the first quarter of 2003 pursuant to the provisions of SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.”

As discontinued operations, we will be required to determine the fair value of our investment, which will be the net amount we expect to realize from the sale of the investment. The investment must be reported at the lesser of our recorded basis or the estimated fair value. If the fair value is less than our recorded basis, we will be required to record an expense equal to the amount, which could be material, by which our basis exceeds the estimated fair value.

We solicited and received indications of value for Protection One Europe from potential buyers. These indications of value are within a range we would be willing to accept. They indicated the recorded goodwill for Protection One Europe had no value. Accordingly, we recorded a $36 million impairment charge in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill at Protection One Europe. We are willing to accept offers in the indicated range due to our ability to use the tax loss on this sale to offset the taxes that would otherwise be

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due from our sale of other investments. We will recognize a $58 million tax benefit in the first quarter of 2003 when Protection One Europe is classified as a discontinued operation.

Ongoing Investigations

Grand Jury Subpoena

On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and the company in general. We are providing information in response to these requests and are fully cooperating in the investigation. We have not been informed that we are a target of the investigation. We are unable to predict the ultimate outcome of the investigation or its impact on us.

Securities and Exchange Commission Inquiry

On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these matters and other matters within the scope of the grand jury investigation. We are unable to predict the ultimate outcome of the inquiry or its impact on us.

Special Committee Investigation

Our board of directors appointed a Special Committee of directors to investigate management matters and matters that are the subject of the grand jury investigation and SEC inquiry. The Special Committee retained counsel and other advisors. The Special Committee investigation has been completed and has not resulted in adjustments to our consolidated financial statements.

FERC Subpoena

On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation (Cleco) and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries.

We have provided information to FERC in response to the subpoena. We believe that our participation in these transactions did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation. See Note 19 of the Notes to Consolidated Financial Statements, “Ongoing Investigations — FERC Subpoena,” for additional information.

Call Option

In August 1998, we entered into a call option with an investment bank related to the issuance of $400 million of our putable/callable notes. This call option is required to be settled by August 2003 through either a cash payment or a remarketing or refinancing of the putable/callable notes. The ultimate value of the call option will be based on the difference between the 10-year United States treasury rate on August 12, 2003 and 5.44%. If the 10-year United States treasury rate on August 12, 2003 is less than 5.44%, we will have a liability to the investment bank at that time. At December 31, 2002, our potential liability under the call option was $62.2 million. Based on the 10-year forward treasury rate on March 14, 2003 of 3.91%, we would be obligated to make a cash payment of approximately $69.1 million to settle the call option if we did not remarket or refinance the notes. The amount of our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. If settled through a remarketing or refinancing, any liability related to the call option will be amortized as a credit to interest expense over the term of the new debt. The investment bank will price the notes to yield a market premium adequate to allow the investment bank to retain proceeds equal to the fair value of the call option at settlement.

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At the time of issuance of the notes in 1998, we were not required by generally accepted accounting principles (GAAP) to account separately for the call option. However, when we began retiring these notes as a part of our overall debt reduction strategy, the portion of the call option associated with the retired notes became a free-standing option required to be treated as a derivative instrument under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). In addition, under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our balance sheet reflects the current fair value of the free standing portion of the call option. For 2002, we recognized a loss of $10.1 million, net of $6.7 million tax benefit, related to the fair value of the call option associated with the putable/callable notes at the time the notes were retired. This loss is included in our consolidated statements of income as part of the gain on extinguishment of debt line item of other income. For 2002, we also recorded an additional non-cash charge of $13.6 million, net of $9.0 million tax benefit, to reflect mark to market changes in the fair value of the call option associated with the retired notes. This charge is reflected in the other line item of other income in our consolidated statements of income. In total, the loss recorded related to the fair value of the call option for the year ended December 31, 2002 was $23.7 million, net of $15.7 million tax benefit.

We intend to repurchase or provide for the repayment of the putable/callable notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. From January 1, 2003 through March 14, 2003, we purchased $35.3 million face value of our putable/callable notes. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.

Impairment Charges

Effective January 1, 2002, we adopted SFAS No. 142, “Accounting for Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” As a result of implementing the new standards, we recorded a charge for the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.

In addition, in the fourth quarter of 2002 we recorded a $79.7 million impairment charge, net of tax benefit and minority interests, to reflect the additional impairment of all remaining goodwill of Protection One’s North America segment. We also recorded a $36 million impairment charge to reflect the impairment of all remaining goodwill at Protection One Europe. These accounting standards, the related charges and other related information are discussed in Note 23 of the Notes to Consolidated Financial Statements, “Impairment Charges.”

Work Force Reductions

During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We recorded a net charge of approximately $21.7 million in 2002 related to this program. We have replaced and may continue to replace some of these employees. For additional information, see Note 29 of the Notes to Consolidated Financial Statements, “Work Force Reductions.”

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. Through December 31, 2002, we incurred $19.3 million for restoration costs, a portion of which was capitalized. We have deferred and recorded as a regulatory asset on our December 31, 2002 consolidated balance sheet restoration costs of approximately $15.0 million. We have received an accounting authority order from the KCC that allows us to accumulate and defer for potential future recovery all operating and carrying costs related to storm restoration.

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 GAAP. The preparation of consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities,

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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, depreciation, revenue recognition, investments, customer accounts, goodwill, intangible assets, income taxes, pensions, post-retirement and post-employment benefits, decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, 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, “Summary of Significant Accounting Policies,” provides 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 Regulation,” and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. 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, 2002, this would reduce our earnings by approximately $351.9 million, net of applicable income taxes.

SFAS No. 71 applies to our electric utility business segment. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See “— Other Information — Electric Utility — Stranded Costs” for additional discussion of the application of SFAS No. 71.

Depreciation

Utility plant is depreciated on the straight-line method at the lesser of rates set by the KCC or rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 2.66% during 2002, 3.03% during 2001 and 2.99% during 2000.

In its rate order of July 25, 2001, the KCC extended the estimated service life for certain of our generating assets, including Wolf Creek and the LaCygne 2 generating station, for regulatory rate making purposes. The estimated retirement date for Wolf Creek was extended from 2025 to 2045, although our operating license for Wolf Creek expires in 2025, and the estimated retirement date for LaCygne 2 was extended to 2032, although the term of our lease for LaCygne 2 expires in 2016. On April 1, 2002, we adopted the new depreciation rates as prescribed in the KCC order. We continue to depreciate Wolf Creek over the term of our operating license, and we continue to depreciate LaCygne 2 over the term of our lease. We have created a regulatory asset for the amount that our depreciation expense exceeds our regulatory depreciation expense.

On an annual basis, our depreciation expense will be reduced by approximately $30.0 million as a result of these extensions. If our generating license for Wolf Creek is not renewed or the term of our lease for LaCygne 2 is not extended, we will need to seek relief from the KCC to recover the remaining cost of these assets.

Pension Benefit Plans

The reported costs of our pension benefit plans, which include our portion of Wolf Creek Nuclear Operating Corporation’s costs, are impacted by the factors listed below.

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The following chart reflects the annual impact of a 0.5 % decrease in certain assumptions. If the discount rate increased by 0.5%, the impact would be a similar amount in the opposite direction.

We recorded pension expense of $5.8 million in 2002 and pension income of $4.0 million in 2001. The $9.8 million increase is due primarily to lower returns on plan assets and an early retirement window that was offered in 2001 and 2002. In 2003 we expect to record approximately $1.8 million of pension income.

Pension plan assets are primarily made up of equity and fixed income investments. The market value of the plan assets has been affected by declines in equity markets. At December 31, 2002, the fair value of pension plan assets was $382.3 million. Actual return on plan assets declined by approximately $2.1 million during 2001 and by approximately $58.5 million during 2002. Absent a substantial recovery in the equity markets, pension costs, cash funding requirements and the additional pension liability could substantially increase in future years.

See Note 15 of the Notes to Consolidated Financials Statements, “Employee Benefit Plans,” for additional information.

Revenue Recognition

Energy Sales

Energy sales are recognized as delivered and include an estimate for energy delivered but unbilled at the end of each year. 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 of fair values 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.

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Monitored Services Revenues

Monitored services revenues are recognized when security services are provided. System installation revenues, sales revenues on equipment upgrades and direct and incremental costs of installations and sales are deferred for residential customers with monitoring service contracts. For commercial customers, revenue recognition is dependent upon each specific customer contract. In instances when the company passes title to a system unaccompanied by a service agreement or the company passes title at a price that it believes is unaffected by an accompanying but undelivered service, the company recognizes revenues and costs in the period incurred. In cases where the company retains title to the system or it prices the system lower than it otherwise would because of an accompanying service agreement, the company defers and amortizes revenues and direct costs.

Deferred system and upgrade installation revenues are recognized over the expected life of the customer utilizing an accelerated method for residential and commercial customers and a straight-line method for Protection One’s Multifamily customers. Deferred costs in excess of deferred revenue are recognized over the initial contract term, utilizing a straight-line method, typically two to three years for residential systems, five years for commercial systems and five to ten years for Multifamily systems. To the extent deferred costs are less than deferred revenues, such costs are recognized over the estimated life of the customer relationship.

Deferred revenues also result from customers who are billed for monitoring and extended service protection in advance of the period in which such services are provided, on a monthly, quarterly or annual basis. Revenues from monitoring activities are recognized in the period such services are provided.

Cumulative Effects of Accounting Changes

Accounting for Goodwill and for the Impairment and Disposal of Long-Lived Assets

Effective January 1, 2002, we adopted SFAS No. 142 and SFAS No. 144. SFAS No. 142 established new standards for accounting for goodwill. SFAS No. 142 continues to require the recognition of goodwill as an asset, but discontinued 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 established 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 goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of the reporting unit, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then we are required to mark the customer account asset down to fair value, by way of recording an impairment, to the extent fair value is less than our book value. To the extent net book value is less than fair value, no impairment would be recorded.

To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, we recorded a charge in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.6 million was related to goodwill and $193.9 million was related to customer accounts.

Accounting for Derivative Instruments and Hedging Activities

Effective January 1, 2001, we adopted SFAS No. 133. We use derivative instruments (primarily swaps, options and futures) to manage interest rate exposure and the commodity price risk inherent in some of our fossil fuel and electricity purchases and 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, in which case changes are reflected in other comprehensive income. Cash flows from derivative instruments are presented in net cash flows from operating activities.

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Derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales are classified as energy trading contracts on our consolidated balance sheets. 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 in 2001 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.

Revenue Recognition

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 this change in accounting principle was a charge to income in 2000 of approximately $3.8 million, net of $1.1 million tax benefit, 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.

Accounting Changes

Accounting for Energy Trading Contracts

In October 2002, the Financial Accounting Standards Board (FASB), through the Emerging Issues Task Force (EITF), issued Issue No. 02-03, which rescinded Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, all new contracts that would otherwise have been accounted for under Issue No. 98-10 and that do not fall within the scope of SFAS No. 133 can no longer be marked-to-market and recorded in earnings as of October 25, 2002. We are not affected by this change in accounting principle and are not required to reclassify any of our contracts. EITF Issue No. 02-03 also requires that energy trading contracts and derivatives, whether settled financially or physically, be reported in the income statement on a net basis effective January 1, 2003. We began to classify our energy trading contracts on a net basis during the third quarter of 2002.

On July 1, 2002, we began reporting mark-to-market gains and losses on energy trading contracts on a net basis, whether realized or unrealized, in our consolidated income statements. Prior to July 1, 2002, we reported gains on these contracts in sales and losses in cost of sales in our consolidated income statements. The changes are reflected in our consolidated financial statements for the year ended December 31, 2002. Prior periods shown in our consolidated financial statements have been reclassified to reflect the effect of this change and to be comparable as required by GAAP. As a result of the net presentation, we expect significant reductions in our energy revenues and expenses from those reported in prior periods, which will not affect gross profit or net income. A summary of the effects of this change for the years ended December 31, 2002, 2001 and 2000 is as follows:

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Changes to Income Statements

OPERATING RESULTS

Westar Energy Consolidated

2002 compared to 2001

We reported a loss of $11.06 per share in 2002 compared to a loss of $0.31 per share in 2001. This greater loss per share was due primarily to the 2002 impairment charges related to monitored services goodwill and customer accounts. A decline in monitored services revenues also contributed to the loss. Improved results from utility operations and declines in cost of sales and operating expenses and increases in other income from monitored services partially offset these items. For additional information, see the segment discussions below.

2001 compared to 2000

We reported a loss of $0.31 per share in 2001 compared to earnings of $1.96 per share 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 in our monitored services segment, and the fourth quarter charge related to a work force reduction. Additionally, investment earnings and extraordinary gains on the retirement of debt were lower in 2001 than in 2000.

Segments of Business

Our business is segmented based on differences in products and services, production processes and management responsibility. We have identified three reportable segments: Electric Utility, Monitored Services and Other.

We manage our business segments’ performance based on their earnings (losses) before interest and taxes (EBIT) because EBIT is the primary measurement used by our management to evaluate segment performance. Our business managers have direct control over the items that affect the EBIT of their segments and we therefore believe EBIT is an appropriate measure of segment performance. 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. Interest expense, income taxes, discontinued operations, cumulative effects of accounting changes and preferred dividends are items that are excluded from the calculation of EBIT. Our computation of EBIT may not be comparable to other similarly titled measures of other

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companies. We provide a reconciliation of EBIT to GAAP income measurements in Note 32 of the Notes to Consolidated Financial Statements, “Segments of Business.”

Electric Utility

We supply electric energy at retail to approximately 647,000 customers in Kansas including the communities of Wichita, Topeka, Lawrence, Manhattan, Salina and Hutchinson. We classify our customers as residential, commercial and industrial as defined in our tariffs. We also supply electric energy at wholesale to the electric distribution systems of 62 Kansas cities and four 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 that purchase and sell electricity in areas outside our historical service territory.

Regulated electric utility sales are significantly impacted by such things as regulation (including rate regulation), customer conservation efforts, wholesale demand, the overall economy of our service area, the weather and competitive forces. Our wholesale sales are impacted by demand outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity.

Our electric sales for the three years ended December 31 were as follows:

The following tables show changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity we generate, for the three years ended December 31. No sales volumes are shown for network integration or power marketing because these activities are not related to electricity we generate.

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Details concerning EBIT and assets attributable to our electric utility segment are summarized in the tables below:

2002 compared to 2001: Energy sales increased $115.7 million, or 9%, due primarily to the $60.1 million in new network integration tariff revenues (see “— Other Information — Electric Utility — Network Integration Transmission Service”), a $33.4 million increase in power marketing, wholesale and interchange revenues and a $27.7 million increase in residential and commercial electric sales revenues. Power marketing, wholesale and interchange revenues increased primarily as a result of increased sales volumes, offset by lower wholesale prices. Favorable weather conditions and a slight increase in the number of utility customers contributed to the increase in residential and commercial electric sales revenues, which were offset by lower retail rates and decreased industrial revenues related to weak economic conditions.

Cost of sales decreased $15.4 million, or 4%, due primarily to a $14.6 million decrease in purchased power expense. Purchased power expense decreased due primarily to the increased availability of our generating units and lower prices.

Gross profit increased $131.2 million, or 14%, for the reasons discussed above. This increase in gross profit also reflects the impact of the adoption of SFAS No. 133 on January 1, 2001. This new standard required that we report a $31.0 million gain in 2001 on certain derivative contracts (derivatives) as a cumulative effect of a change in accounting principle rather than include the gain in gross profit. All gains and losses after January 1, 2001 on our derivatives that are not designated as hedges are reflected in gross profit. Had we included the $31.0 million gain in revenues in 2001, gross profit would have increased $100.1 million rather than $131.2 million.

Operating expenses increased $69.0 million, or 10%, due primarily to the charges associated with the network integration transmission tariff, reserve for potential liabilities to Mr. Wittig and Mr. Lake, employee severance costs related to the work force reduction and the compensation expense associated with an exchange of previously granted restricted share units as discussed in Note 15 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans — Stock Based Compensation Plans.” These increases were partially offset by a $13.4 million decrease in depreciation expense related to the change in depreciation rates as discussed above in “— Critical Accounting Policies — Depreciation.” In addition, our maintenance expense declined $22.6 million, or 19%, due primarily to the lower forced outage rates of our generating units.

Due to the above factors, income from utility operations increased $62.2 million, or 29%. A decrease in other expense of $22.3 million was due primarily to recording a non-cash mark-to-market charge on the call option of the putable/callable notes as discussed in “— Liquidity and Capital Resources” below. EBIT increased $39.9 million as a result.

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2001 compared to 2000: Energy sales decreased $52.3 million, or 4%. Residential sales declined 7% and power marketing, wholesale and interchange sales declined 11%. Residential sales decreased due to weather conditions and our rate decrease, while power marketing, wholesale and interchange sales decreased because of lower prices and more power available in the market. Cost of sales increased $13.7 million, or 4%, which was due principally to an increase in our natural gas fuel expenses resulting from the purchase of fuel for new generating units that began operating during 2001.

As a result of the decline in sales and the increase in cost of sales, gross profit decreased $66.0 million, or 7%. This decline in gross profit also reflects the impact of the adoption of SFAS No. 133 on January 1, 2001. This new standard required that we report a $31.0 million gain on certain derivatives as a cumulative effect of a change in accounting principle rather than include the gain in gross profit. Had we been permitted to classify this accounting change as an increase to revenues, gross profit would have declined by $35.0 million rather than $66.0 million.

Operating expenses increased $45.7 million due primarily to recording approximately $8.7 million of costs associated with the terminated Public Service Company of New Mexico merger transaction, approximately $14.3 million in employee-severance costs related to the 2001 work force reductions, an increase in our pension and benefit expenses and an increase in general maintenance expenses.

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 take into consideration Protection One’s minority interest of approximately 12% at December 31, 2002, 13% at December 31, 2001, and 15% at December 31, 2000. As discussed above, our monitored services operations will be reported as discontinued operations as required by of SFAS No. 144 during the first quarter of 2003.

Details concerning EBIT and assets attributable to our monitored services segment are as follows:

2002 compared to 2001: Sales decreased $60.4 million due primarily to a decline in the average customer base and the renewal of existing customers for extended contract periods with a lower monthly rate. The monitored services segment experienced a net decline of 62,656 customers in 2002, which is attributable primarily to customer attrition. Although net customers decreased for the year, Protection One had a favorable decline in attrition in 2002 compared to 2001 due to the reasons discussed in “— Other Information — Monitored Services — Attrition” below.

Protection One expects that the decline in its customer base will continue until the efforts it is making to generate 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. For 2003, Protection One’s focus is on improving returns on invested capital by realizing economies of scale from increasing customer density in the largest urban markets in the United States. It plans to accomplish this by improving customer retention. See “— Other Information — Monitored Services — Attrition” below for additional information.

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Cost of sales decreased $11.9 million due primarily to a reduction of telecommunication costs and consolidation of Protection One’s monitoring functions. Operating expenses increased $310.4 million due primarily to the 2002 impairment charges. Partially offsetting the increase in operating expenses was a decline in depreciation and amortization expense, which reflects a reduction in customer account amortization related to the impairment charges and elimination of goodwill amortization due to the implementation of SFAS No. 142. Also partially offsetting the increase in operating expenses were reductions in professional fees and outside services because of the completion of system integration projects and lower legal costs, a decrease in wage expense because of consolidation efforts, and a decline in bad debt expense and collection costs.

As a result of the decline in gross profit and the increase in operating expenses, loss before interest and taxes increased $292.8 million. Monitored services’ total assets decreased approximately $1.2 billion primarily as a result of the impairment of goodwill and customer account assets.

2001 compared to 2000: Sales decreased $121.3 million due primarily to a decline in the monitored services segment’s average customer base and the disposition of certain operations. The monitored services segment experienced a net decline of 272,549 customers in 2001. This decrease in customers is attributable primarily 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 a given 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 location.

Loss before interest and taxes increased $71.4 million due primarily to the decrease in sales. Cost of sales decreased $41.7 million due primarily 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.

Other

Other includes an approximate 45% interest in ONEOK at December 31, 2002, and other investments in the aggregate not material to our business or results of operations. Details concerning EBIT attributable to this segment are as follows: