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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 1-7324

KANSAS GAS AND ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

P.O. BOX 208

Wichita, Kansas 67201

(316) 261-6611

(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: None

Securities registered pursuant to section 12(g) of the Act: None

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  ¨    No  x

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

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

Registrant meets the conditions of General Instruction I(1)(a) and (b) to Form 10-K for certain wholly owned subsidiaries and is therefore filing an abbreviated form.

Documents Incorporated by Reference: None

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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 Westar Energy, Inc.’s Debt Reduction and Restructuring Plan filed with the Kansas Corporation Commission on February 6, 2003; compliance with debt and other restrictive covenants; interest; the financial condition of other Westar Energy, Inc., subsidiaries and their impact on Westar Energy, Inc.’s results; environmental matters; nuclear operations; 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 Westar Energy, Inc.’s 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 Westar Energy, Inc’s interests in ONEOK, Inc., and the potential sale of certain of Westar Energy, Inc.’s subsidiaries; the impact on Westar Energy, Inc. of the federal grand jury subpoena by the United States Attorney’s Office requesting certain information from Westar Energy, Inc.; the impact on Westar Energy, Inc. of 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 Westar Energy, Inc.; the impact of changes in interest rates generally and, specifically, changes in the London Interbank offer rate (LIBOR) on the fair value of our allocated share of Westar Energy, Inc.’s energy swap transactions; changes in the 10-year United States treasury rates and the corresponding impact on the fair value of Westar Energy, Inc.’s call option contract; homeland security considerations; 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

Kansas Gas and Electric Company is a rate-regulated electric utility incorporated in 1990 in the State of Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “KGE,” “we,” “us,” “our” or similar words are to Kansas Gas and Electric Company. We are a wholly owned subsidiary of Westar Energy, Inc. (Westar Energy) and we provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. We are engaged principally in the generation, purchase, transmission, distribution and sale of electricity in southeastern Kansas, including the Wichita metropolitan area. Our corporate headquarters are located in Wichita, Kansas.

We own 47% of Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek Generating Station (Wolf Creek), our nuclear powered generating facility. We record our proportionate share of all transactions of WCNOC as we do other jointly owned facilities.

SIGNIFICANT BUSINESS DEVELOPMENTS

Overview

A number of significant developments have impacted us and our business operations since January 2002, either directly or indirectly through Westar Energy.

New Chief Executive Officer and Senior Management Team

James S. Haines, Jr., joined Westar Energy in December 2002 as its chief executive officer and president and a member of its board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with Westar Energy and its 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 Westar Energy’s 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 Westar Energy and have a strong background in the electric utility business. Douglas T. Lake, Westar Energy’s executive vice president and chief strategic officer,

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resigned as a member of its board of directors and was placed on unpaid leave from all of his other positions with Westar Energy and its affiliates on December 6, 2002.

See Note 19 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about Westar Energy’s potential liabilities to Mr. Wittig and Mr. Lake.

KCC Orders and Westar Energy’s Debt Reduction and Restructuring Plan

On February 6, 2003, Westar Energy filed the Debt Reduction Plan with the KCC outlining Westar Energy’s plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of Westar Energy’s non-utility assets, including its interests in its monitored services subsidiaries and its equity investment interests. As part of the Debt Reduction Plan, Westar Energy’s first quarter 2003 dividend on its 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 Westar Energy form a utility-only subsidiary for its former KPL electric utility division (KPL) no later than August 1, 2003.

The Debt Reduction Plan replaced a previous financial plan to which Westar Energy 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 Westar Energy 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 its 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 Westar Energy and we seek KCC approval before entering into certain transactions with a non-utility affiliate. Following Westar Energy’s 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 Westar Energy’s utility businesses, i.e., KPL and us, not exceed $1.67 billion.

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. Westar Energy is 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.

Ongoing Investigations

Grand Jury Subpoena

On September 17, 2002, Westar Energy was served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning Westar Energy’s use of aircraft and its annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on Westar Energy and certain of its 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 Westar Energy in general. Westar Energy is providing information in response to these requests and is fully cooperating in the investigation. Westar Energy has not been informed that it

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is a target of the investigation. Westar Energy is unable to predict the ultimate outcome of the investigation or its impact on Westar Energy.

Special Committee Investigation

Westar Energy’s 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 Westar Energy’s or our consolidated financial statements.

FERC Subpoena

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

Among the issues being reviewed by FERC are transactions Westar Energy conducted with third parties to facilitate power transfers between Westar Energy’s system operations and its marketing operations. While these energy transactions do not apply to us, the FERC investigation includes all transactions of both Westar Energy and us.

Westar Energy has provided information to FERC in response to the subpoena and believes that its participation in these transactions did not violate FERC rules and regulations. However, Westar Energy is unable to predict the ultimate outcome of the investigation. See Note 14 of the Notes to Consolidated Financial Statements, “Ongoing Investigations — FERC Subpoena,” for additional information.

Work Force Reductions

During 2002, Westar Energy reduced the utility work force we both utilize by approximately 400 employees through a voluntary separation program. Westar Energy recorded a net charge of approximately $21.7 million in 2002, a portion of which was allocated to us, related to this program. Westar Energy has replaced and may continue to replace some of these employees.

Ice Storm

In late January 2002, a severe ice storm swept through our service area causing extensive damage and loss of power to numerous customers. Through December 31, 2002, we incurred $12.7 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 $9.0 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.

ELECTRIC UTILITY OPERATIONS

General

We supply electric energy at retail to approximately 296,000 customers in Kansas. 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 26 Kansas cities. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities.

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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, 2002. No sales volumes are shown for network integration because this activity is not related to electricity we generate.

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Generation Capacity

We have 2,613 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 2,100 MW occurred on July 26, 2002. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 17% above system peak responsibility at the time of the peak. Our all time peak system net load of 2,111 MW occurred on August 11, 1999. We do not anticipate needing additional generating capacity through 2005.

We have an agreement with Midwest Energy, Inc. to provide it with peaking capacity of 60 MW through May 2008.

Fossil Fuel Generation

Fuel Mix

Based on the quantity of heat produced during the generation of electricity (MMBtu), the 2002 actual fuel mix was 61% coal, 31% nuclear and 8% 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 442 MW (our 20% share). Westar Energy, the operator of JEC, and we have a long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company, to supply coal to JEC from mines located in the Powder River Basin in Wyoming. The contract expires December 31, 2020. The contract contains a schedule of minimum annual MMBtu delivery quantities. The 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 $1.0 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 (our 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

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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.

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.

Natural Gas

We use natural gas as a primary fuel in our Gordon Evans, Murray Gill and Neosho Energy Centers. Natural gas for these 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 5,728,474 MMBtu of natural gas on the spot market for a total cost of $19.7 million. Natural gas accounted for approximately 4% of our total fuel burned during 2002.

During the third quarter of 2001, Westar Energy entered into hedging relationships to manage commodity price risk associated with future natural gas purchases in order to protect us and our customers from adverse price fluctuations in the natural gas market. We are allocated our proportionate share of the benefits and costs of Westar Energy’s commodity price risk management program based on fuel forecasts for Westar Energy and us. 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.”

We meet a portion of our natural gas transportation requirements through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. The firm transportation agreement that serves Gordon Evans and Murray Gill extends through April 1, 2010, and the agreement for the Neosho facility 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 3% of our total fuel burned during 2002.

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.

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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.

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.

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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 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

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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.

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 have a material adverse impact on our operations and our financial condition. Our rates are approximately 19% 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 Statement of Financial Accounting Standards (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

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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 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 $32.9 million, and the associated revenues were approximately $30.1 million, for a net expense of approximately $2.8 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.

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 we filed applications with the KCC for an increase in retail rates. On July 25, 2001, the KCC ordered an annual reduction in our electric rates of $41.2 million.

On August 9, 2001, Westar Energy and we 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 acquisition premium and a deferred gain on the sale and leaseback of LaCygne 2 and several other issues. On September 5, 2001, the KCC issued an order denying our motion for reconsideration, which did not change our rate reduction. On November 9, 2001, we filed an appeal of the KCC decisions to 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.”

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Environmental Matters

We currently hold all federal and state environmental approvals required for the operation of all of our generating units. We believe we are 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).

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 $1.0 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 12 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies,” and such information is incorporated herein by reference.

EMPLOYEES

Westar Energy provides all employees we utilize. As of February 28, 2003, Westar Energy had approximately 1,900 utility employees. Its 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,

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2003. Westar Energy is currently discussing modifications to its existing contract with union representatives and expects these discussions to result in an agreement. Westar Energy anticipates that formal bargaining will begin in April 2003 if these discussions are unsuccessful.

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ITEM 2. PROPERTIES

ELECTRIC UTILITY FACILITIES

We own approximately 2,200 miles of transmission lines, approximately 10,000 miles of overhead distribution lines and approximately 1,900 miles of underground distribution lines.

Substantially all of our utility properties are encumbered by a first priority mortgage pursuant to which bonds have been issued and are outstanding.

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ITEM 3. LEGAL PROCEEDINGS

Information on our legal proceedings is set forth in Notes 3, 13, 14 and 19 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

Information required by Item 4 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All of our common stock is owned by Westar Energy and is not traded on an established public trading market.

ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

In Management’s Discussion and Analysis, we discuss the general financial condition, significant annual changes and our operating results. 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, either directly or indirectly through Westar Energy.

New Chief Executive Officer and Senior Management Team

James S. Haines, Jr., joined Westar Energy in December 2002 as its chief executive officer and president and a member of its board of directors. He replaced David C. Wittig, who resigned on November 22, 2002 from all of his positions with Westar Energy and its 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.

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Mr. Haines added new members to Westar Energy’s 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, Westar Energy’s executive vice president and chief strategic officer, resigned as a member of its board of directors and was placed on unpaid leave from all of his other positions with Westar Energy and its affiliates on December 6, 2002.

See Note 19 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake,” for information about Westar Energy’s potential liabilities to Mr. Wittig and Mr. Lake.

KCC Orders and Westar Energy’s Debt Reduction and Restructuring Plan

On February 6, 2003, Westar Energy filed the Debt Reduction Plan with the KCC outlining its plans for paying down debt and restructuring the company. The Debt Reduction Plan calls for the sale of Westar Energy’s non-utility assets, including its interests in its monitored services subsidiaries and its equity investment interests. As part of the Debt Reduction Plan, Westar Energy’s first quarter 2003 dividend on its 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 Westar Energy form a utility-only subsidiary for its former KPL electric utility division (KPL) no later than August 1, 2003.

The Debt Reduction Plan replaced a previous financial plan to which Westar Energy 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 Westar Energy 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 its 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 Westar Energy and we seek KCC approval before entering into certain transactions with a non-utility affiliate. Following Westar Energy’s 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 Westar Energy’s utility businesses, KPL and us, not exceed $1.67 billion.

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. Westar Energy is 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.

Ongoing Investigations

Grand Jury Subpoena

On September 17, 2002, Westar Energy was served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning Westar Energy’s use of aircraft and its annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on Westar Energy and certain of its employees requesting further information concerning the use of aircraft; executive

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compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock; and Westar Energy in general. Westar Energy is providing information in response to these requests and is fully cooperating in the investigation. Westar Energy has not been informed that it is a target of the investigation. Westar Energy is unable to predict the ultimate outcome of the investigation or its impact on Westar Energy.

Special Committee Investigation

Westar Energy’s 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 Westar Energy’s or our consolidated financial statements.

FERC Subpoena

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

Among the issues being reviewed by FERC are transactions Westar Energy conducted with third parties to facilitate power transfers between Westar Energy’s system operations and its marketing operations. While these energy transactions do not apply to us, the FERC investigation includes all transactions of both Westar Energy and us.

Westar Energy has provided information to FERC in response to the subpoena and believes that its participation in these transactions did not violate FERC rules and regulations. However, Westar Energy is unable to predict the ultimate outcome of the investigation. See Note 14 of the Notes to Consolidated Financial Statements, “Ongoing Investigations — FERC Subpoena,” for additional information.

Work Force Reductions

During 2002, Westar Energy reduced the utility work force we both utilize by approximately 400 employees through a voluntary separation program. Westar Energy recorded a net charge of approximately $21.7 million in 2002, a portion of which was allocated to us, related to this program. Westar Energy has replaced and may continue to replace some of these employees.

Ice Storm

In late January 2002, a severe ice storm swept through our service area causing extensive damage and loss of power to numerous customers. Through December 31, 2002, we incurred $12.7 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 $9.0 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 generally accepted accounting principles (GAAP). The preparation of consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, depreciation, sales recognition, goodwill, intangible assets, income taxes, 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

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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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

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 $227.1 million, net of applicable income taxes.

SFAS No. 71 applies to our electric operations. We do not anticipate the discontinuation of SFAS No. 71 in the foreseeable future. See “— Other Information — 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 2.37% during 2002, 2.80% during 2001 and 2.81% 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 $18.0 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.

Sales Recognition

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

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actually achieved from these activities could vary materially from intended results and could unfavorably affect our financial results.

Cumulative Effect of Accounting Change

Accounting for Derivative Instruments and Hedging Activities

Effective January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, SFAS No. 133). Westar Energy uses derivative instruments (primarily swaps, options and futures) to manage the commodity price risk inherent in some of our fossil fuel and electricity purchases and sales. We are allocated our proportionate share of the benefits and costs of Westar Energy’s commodity price risk management program based on fuel forecasts for Westar Energy and us. These allocated benefits and costs are recognized in our financial statements. Under SFAS No. 133, all derivative instruments, including our energy trading contracts, are recorded on our consolidated balance sheets 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.

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 $12.9 million, net of $8.5 million of tax. This gain is presented on our consolidated statement of income for 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 “— Sales Recognition.” Accounting for derivatives under SFAS No. 133 will increase volatility of our future earnings.

Accounting Change

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 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

We supply electric energy at retail to approximately 296,000 customers in Kansas. 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 26 Kansas cities. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities.

Regulated electric utility sales are significantly impacted by such things as the weather, regulation (including rate regulation), customer conservation efforts, wholesale demand, the overall economy of our service area 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 years ended December 31, 2002, 2001 and 2000 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, 2002. No sales volumes are shown for network integration because this activity is not related to electricity we generate.

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2002 compared to 2001

Sales increased $64.1 million, or 10%, due primarily to the $30.1 million in new network integration tariff revenues and a $42.8 million increase in wholesale and interchange revenues due in large part to increased sales volumes despite lower wholesale prices. Residential revenues increased minimally despite an approximate 6% increase in sales volumes. The sales volumes increased primarily due to favorable weather conditions, but the revenues did not increase at the same rate as a result of the July 2001 rate decrease. These increases were partially offset by declines in commercial electric sales revenues and industrial revenues. The same factors that contributed to the decline in residential revenues also caused the commercial revenues to decline. Lower industrial demand related to weak economic conditions caused the decline in industrial sales.

Cost of sales increased $5.1 million, or 3%. Fuel expense decreased $8.4 million and purchased power costs decreased $7.4 million. Purchased power expense decreased due primarily to the increased availability of our units and lower prices. Partially offsetting these reductions were $20.9 million in higher costs associated with the dispatching of electric power.

Gross profit increased $59.0 million primarily due to the increase in sales being higher than the increase in cost of sales. 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 $21.4 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 $21.4 million gain in revenues in 2001, gross profit would have increased $37.6 million rather than $59.0 million.

Operating expenses increased $18.5 million, or 5%, due primarily to the charges associated with the network integration transmission tariff and increased selling, general and administrative expenses due to allocated compensation charges. These increases were partially offset by a $11.2 million decrease in depreciation expense primarily related to the change in depreciation rates as discussed above in “— Critical Accounting Policies — Depreciation.” In addition, our maintenance expense declined $12.9 million, or 20%, due primarily to the lower forced outage rates of our generating units.

Income from operations increased $40.5 million, or 43%, for the reasons discussed above. Other expenses increased $2.1 million due primarily to recording a loss on the disposition of our office building in Wichita, Kansas, during 2002.

We recorded an income tax expense in 2002 of $16.1 million, which reflects an effective income tax rate expense of 21%. In 2001, we recorded an income tax benefit of $1.6 million, which reflects an effective income tax rate benefit of 4%. This change is due primarily to higher earnings before income taxes in 2002. Earnings before

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income taxes increased due to the increase in sales being greater than the increases in our expenses as discussed above. Our effective tax rates are also affected by the amortization of prior years’ investment tax credits and the tax benefit from corporate-owned life insurance.

Net income increased $9.3 million, or 19% as a result of the items discussed above.

2001 compared to 2000

Retail sales decreased due to a decrease in retail sales volumes primarily caused by weather conditions and lower retail rates due to the rate decrease ordered in July 2001. Wholesale and interchange sales revenues also contributed to the decrease because of lower prices, although the wholesale and interchange sales volumes increased slightly.

Cost of sales increased $13.1 million, or 9%, due primarily to an increase in purchased power costs of $14.2 million associated with the dispatching of electric power. Partially offsetting this increase was a decline in fuel expense of $6.5 million.

Gross profit decreased $67.4 million, or 13%, due to the decline in sales and the increase in cost of sales. 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 $21.4 million gain in 2001 on certain 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 been permitted to classify this accounting change as a reduction to cost of sales, gross profit would have declined by $46.0 million rather than $67.4 million.

Operating expenses increased $16.2 million, or 5%, due primarily to increased selling, general and administrative expenses due to a $7.3 million increase in allocated pension and benefit costs and a $3.7 million increase in allocated employee salaries. Operating and maintenance expenses also increased due primarily to an increase in the costs associated with dispatching power and an increase in general plant maintenance expenses. Income from operations decreased $83.6 million, or 47%, for the reasons discussed above.

We recorded an income tax benefit in 2001 of $1.6 million, which reflects an effective income tax rate benefit of 4%. In 2000, we recorded an income tax expense of $34.0 million, which reflects an effective income tax rate expense of 28%. This change is due primarily to lower earnings before income taxes in 2001. Our effective tax rates are also affected by the amortization of prior years’ investment tax credits and the tax benefit from corporate-owned life insurance.

For the year ended December 31, 2001, we recorded a cumulative effect of accounting change related to the mark-to-market adjustment on fuel derivatives as prescribed by SFAS No. 133. Net income decreased $36.5 million, or 42% as a result of the items discussed above.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Westar Energy believes it will have sufficient cash to fund future operations of its business (including us), debt reductions, including the annual $100 million debt reductions in 2003 and 2004 ordered by the KCC, and the payment of dividends, from a combination of cash on hand, cash flow, proceeds from the sales of its non-utility and non-core assets and available borrowings under its revolving credit facility. Uncertainties affecting its ability to meet these requirements include, among others, the factors affecting sales described above, economic conditions, including the impact of inflation on operating expenses, regulatory actions, including the KCC orders received in the last quarter of 2002 and first quarter of 2003, Westar Energy’s ability to implement the Debt Reduction Plan, compliance with future environmental regulations and the impact of its monitored services’ operations and financial condition.

Most of our cash requirements consist of capital expenditures and maintenance costs designed to improve and maintain facilities that provide electric service and meet future customer service requirements. Our ability to

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provide the cash or debt to fund our capital expenditures depends upon many things, including available resources, our financial condition and current market conditions.

Our internally generated cash is generally sufficient to fund operations and debt service payments. We do not maintain independent short-term credit facilities and rely on Westar Energy for short-term cash needs. If Westar Energy is unable to borrow under its credit facilities, we could have a short-term liquidity issue that could require us to obtain a credit facility for our short-term cash needs and that could result in higher borrowing costs.

At December 31, 2002, current maturities of long-term debt increased $135.0 million from 2001 due primarily to the upcoming maturity of our 7.6% first mortgage bonds that are due December 15, 2003. We have irrevocably deposited with the bond trustee funds sufficient to provide for the future principal and interest payments on these first mortgage bonds.

Capital Resources

Westar Energy’s Debt Reduction Plan provides for a systematic disposal of its non-utility and non-core assets and, if necessary, a sale of Westar Energy equity. The proceeds of these transactions will be used to reduce debt. Westar Energy may reduce its and our debt pursuant to terms stated in the debt agreements or through open market purchases or tender offers. Westar Energy may engage a financial advisor to assist in completing debt repurchases in the most cost-effective manner.

We have registered debt securities for sale with the SEC. As of December 31, 2002, these included $50 million of our first mortgage bonds. Any issuance of debt would require that we seek KCC approval.

Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on, or 10% of the principal amount of, all of our first mortgage bonds outstanding after giving effect to the proposed issuance. The amount of our first mortgage bonds authorized by our mortgage is limited to a maximum of $2 billion. Amounts of additional bonds that may be issued are subject to property, earnings, and certain restrictive provisions of the mortgage. As of December 31, 2002, approximately $302.5 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

Cash Flows from (used in) Operating Activities

Our primary source of operating cash flows is from our electric utility operations. Cash flows from operating activities increased $6.6 million to $152.2 million in 2002, from $145.6 million in 2001. This increase is mostly attributable to changes in our working capital and the increase in utility gross margin for 2002 compared to 2001.

Cash flows from operating activities decreased $59.3 million to $145.6 million in 2001, from $204.9 million in 2000. This decrease is mostly attributable to changes in working capital and the decrease in utility gross margin for 2001 compared to 2000.

Cash Flows from (used in) Investing Activities

In general, cash used for investing purposes relates to the maintenance of our utility operations. Cash flows used in investing activities decreased $24.8 million to $58.0 million in 2002 from $82.8 million in 2001 due primarily to the timing of the refueling and maintenance outages at Wolf Creek.

Cash Flows from (used in) Financing Activities

Net cash used in financing activities totaled $93.6 million for the year ended December 31, 2002 as compared to $64.4 million for the same period in 2001 due primarily to $135.0 million of funds that have been irrevocably deposited with the bond trustee to provide for the repayment of our 7.6% first mortgage bonds that are due December 15, 2003. Partially offsetting this increase was a slight rise in net advances from Westar Energy and the suspension of dividends to Westar Energy.

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Future Cash Requirements

We believe that internally generated funds and borrowings from Westar Energy will be sufficient to meet our operating and capital expenditure requirements and debt service payments through at least the year 2005, assuming Westar Energy’s Debt Reduction Plan is approved by the KCC.

The November 8, 2002 KCC order requires Westar Energy to reduce its and our debt by $100 million annually in each of the next two years from internally generated cash flow. While Westar Energy believes it can generate this level of internally generated cash flow, if it fails to meet this requirement, the KCC may, among other things, require Westar Energy to reduce or eliminate its dividend or issue equity securities. In the Debt Reduction Plan, Westar Energy anticipates meeting the $100 million debt reduction goal.

Our business requires significant capital investments. Through 2005, we expect we will need cash mostly for ongoing utility construction and maintenance programs designed to maintain and improve facilities providing electric service. We do not anticipate needing additional generating capacity through 2005.

Capital expenditures for 2002 and anticipated capital expenditures for 2003 through 2005 are as follows:

These estimates are prepared for planning purposes and will be revised from time to time as discussed in Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies.” Actual expenditures will differ from our estimates.

In 2003, $135 million of our first mortgage bonds will mature. We have irrevocably deposited $135 million with the bond trustee to provide for repayment of this obligation. These funds were provided to us through Westar Energy’s June 6, 2002 refinancing (see “— Refinancing,” below). Additionally, $65 million of our first mortgage bonds will mature in 2005.

Contractual Cash Obligations

In the course of our business activities, we enter into a variety of contractual obligations. Some of these result in direct obligations that are reflected in our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, that are not reflected in our underlying consolidated financial statements. The obligations listed below do not include amounts for on-going needs for which no contractual obligations existed as of December 31, 2002, and represent only amounts that we were contractually obligated to meet as of December 31, 2002. The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2002:

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Long-term debt: Our long-term debt existing as of December 31, 2002 is debt that has a final maturity of January 1, 2003 or later (including current maturities of long-term debt). See Note 9 of the Notes to Consolidated Financial Statements, “Long-Term Debt,” for detailed information.

Operating leases: We maintain operating leases in the ordinary course of our business activities. These leases include those for office space, operating facilities, office equipment and operating equipment. These leases have various terms and expiration dates from 1 to 16 years. See Note 15 of the Notes to Consolidated Financial Statements, “Leases,” for additional information.

Fossil fuel: To supply a portion of the fossil fuel requirements for our generating plants, we have entered into various commitments to obtain and deliver coal and for natural gas transportation. Some of these contracts contain provisions for price escalation and minimum purchase commitments. For additional information, see Note 12 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies — Fuel Commitments.”

Nuclear fuel: To supply a portion of the fuel requirements for Wolf Creek generating station, we have entered into various commitments to obtain nuclear fuel consisting of uranium concentrates, conversion and enrichment. See Note 12 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies — Fuel Commitments,” for more details.

Unconditional purchase obligations: We use purchase obligations as part of our ongoing operations and construction program. See Note 12 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies — Purchase Orders and Contracts,” for additional information.

Debt Covenants

Westar Energy’s debt financing agreements require, among other restrictions, that it satisfy certain financial covenants. These debt instruments contain restrictions based on EBITDA. The definition of EBITDA varies among the various indentures. EBITDA is generally derived by adding to income (loss) before income taxes, the sum of interest expense and depreciation and amortization expense. However, under the varying definitions of the indentures, additional adjustments are required. A violation of these restrictions would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable. Westar Energy is in compliance with these covenants. The most restrictive of these covenants in Westar Energy’s debt instruments are as follows:

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The indentures contain other covenants that impose operational restrictions that are not as burdensome as those listed above and none are based on credit ratings. A violation of the indenture covenants would result in an event of default that would allow the lenders to declare all amounts outstanding immediately due and payable.

Sale of Accounts Receivable

On July 28, 2000, Westar Energy and we entered into an agreement under which we transfer an undivided percentage ownership interest in a revolving pool of our accounts receivable arising from the sale of electricity to a multi-seller conduit administered by an independent financial institution through the use of a special purpose entity (SPE). We account for this transfer as a sale in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The agreement was amended on July 25, 2002 and is annually renewable upon agreement by all parties. The amendment to the agreement extended the term until July 23, 2003 and limited the amount of the accounts receivable Westar Energy and we had a right to sell during certain periods to $125 million.

Under the terms of the agreement, Westar Energy and we may transfer accounts receivable to the bankruptcy-remote SPE, and the conduit must purchase from the SPE an undivided ownership interest of up to $125 million in those receivables. The SPE has been structured to be legally separate from us, but it is wholly owned by Westar Energy and consolidated by us. The percentage ownership interest in receivables purchased by the conduit may increase or decrease over time, depending on the characteristics of the SPE’s receivables, including delinquency rates and debtor concentrations.

Under the terms of the agreement, the conduit pays the SPE the face amount of the undivided interest at the time of purchase. Subsequent to the initial purchase, additional interests are sold and collections applied by the SPE to the conduit, resulting in an adjustment to the outstanding conduit interest.

We record administrative expense on the undivided interest owned by the conduit, which was $1.3 million for the year ended 2002, $2.5 million for the year ended 2001 and $1.6 million for the year ended 2000. These expenses are included in other income (expense) in our consolidated statements of income.

The outstanding balance of SPE receivables was $48.2 million at December 31, 2002 and $43.3 million at December 31, 2001, which is net of an undivided interest of $110.0 million and $100.0 million, respectively, in receivables sold by the SPE to the conduit. Our retained interest in the SPE’s receivables is reported at fair value and is subordinate to, and provides credit enhancement for, the conduit’s ownership interest in the SPE’s receivables. Our retained interest is available to the conduit to pay any fees or expenses due to the conduit and to absorb all credit losses incurred on any of the SPE’s receivables. The retained interest is included in accounts receivable, net, in our consolidated balance sheets.

A termination event will be triggered under the terms of the agreement if Westar Energy’s or our credit rating ceases to be at least BB- by Standard & Poor’s Ratings Group (S&P) or if the issuer credit rating for Westar Energy ceases to be at least Ba3 by Moody’s Investors Service (Moody’s). If a termination event were to occur, the administrative agent would be required to give notice to us at least five business days prior to a termination of the facility. This notice provision allows for the administrative agent to waive the termination event by not giving notice or, in the event notice is given, allows us to repay the facility.

Refinancings

On May 10, 2002, Westar Energy completed offerings for $365 million of its first mortgage bonds and $400 million of its unsecured senior notes, both of which will be due on May 1, 2007. The first mortgage bonds bear interest at an annual rate of 7 ⁷/8% and the unsecured senior notes bear interest at an annual rate of 9 ³/4%. Interest on the first mortgage bonds and unsecured senior notes is payable semi-annually on May 1 and November 1 of each year. The net proceeds from these offerings were used to repay outstanding indebtedness of $547 million under

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Westar Energy’s existing secured bank term loan, provide for the repayment of $100 million of Westar Energy’s 7.25% first mortgage bonds due August 15, 2002 together with accrued interest, reduce the outstanding balance on Westar Energy’s existing secured revolving credit facility and pay fees and expenses of the transactions. In conjunction with the May 10, 2002 financing, Westar Energy amended its secured revolving credit facility to reduce the total commitment under the facility to $400 million from $500 million and to release another $100 million of Westar Energy’s first mortgage bonds from collateral.

On June 6, 2002, Westar Energy entered into a secured credit agreement providing for a $585 million term loan and a $150 million revolving credit facility, each maturing on June 6, 2005, provided that if Westar Energy has not refinanced or provided for the payment of its putable/callable notes due August 15, 2003, or its 6.875% senior unsecured notes due August 1, 2004, at least 60 days prior to either of the respective due dates, the maturity date is the date 60 days prior to either of the respective due dates. All loans under the credit agreement are secured by our first mortgage bonds. The proceeds of the term loan were used to retire an existing $400 million revolving credit facility of Westar Energy with an outstanding principal balance of $380 million, to provide for the repayment at maturity of $135 million principal amount of our first mortgage bonds due December 15, 2003 together with accrued interest, to repurchase approximately $45 million of Westar Energy’s outstanding unsecured notes and to pay customary fees and expenses of the transactions.

Capital Structure

Our capital structure at December 31, 2002 and 2001 was as follows:

Credit Ratings

S&P, Moody’s and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate Westar Energy’s and our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal on our securities.

On April 29, 2002, Moody’s confirmed Westar Energy’s ratings with a negative outlook. On January 29, 2003, Fitch revised our and Westar Energy’s Rating Watch status from evolving to negative, but on March 11, 2003, Fitch affirmed its ratings for Westar Energy and us and removed the ratings from Rating Watch Negative. Following the filing of Westar Energy’s Debt Reduction Plan with the KCC, S&P affirmed its ratings for Westar Energy and us and removed all ratings from CreditWatch Negative changing such designation to CreditWatch Developing on February 6, 2003.

As of March 14, 2003, ratings with these agencies are as follows:

In general, declines in Westar Energy’s and our credit ratings make debt financing more costly and more difficult to obtain on terms that are economically favorable to us. We do not have any credit rating conditions in any of the agreements under which our debt has been issued, except for conditions in the agreements governing the sale of accounts receivable discussed above.

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OTHER INFORMATION

City of Wichita Franchise

Our franchise with the City of Wichita to provide retail electric service is effective through December 1, 2003. We are currently negotiating with the City of Wichita for a long-term franchise agreement. There can be no assurance that we can successfully renegotiate the franchise with terms similar, or as favorable, as those in the current franchise. Under Kansas law, we will continue to have the right to serve the customers in Wichita following the expiration of the franchise. Customers within the Wichita metropolitan area account for approximately 46% of our total energy sales volumes.

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 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 $32.9 million, and the associated revenues were approximately $30.1 million, for a net expense of approximately $2.8 million. The revenues received are reflected in electric operating revenues, and the related charges are expensed.

Stranded Costs

Stranded costs for a utility business are commitments or investments in, and carrying costs on, property, plant and equipment, and other regulatory assets that exceed the amount that can be recovered in a competitive market. We currently apply accounting standards that recognize the economic effects of rate regulation and record regulatory assets and liabilities related to our operations. If we determine that we no longer meet the criteria of SFAS No. 71, we may have a material non-cash charge to earnings. Reasons for discontinuing SFAS No. 71 accounting treatment include increasing competition that restricts our ability to charge prices needed to recover costs already incurred, a significant change by regulators from a cost-based rate regulation to another form of rate regulation. We periodically review SFAS No. 71 criteria and believe our net regulatory assets, including those related to generation, are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based upon competitive or other events, such as successful municipalization by areas we serve, the value of our net regulatory assets and our utility plant investments, particularly Wolf Creek, may be significantly impacted.

Regulatory changes could adversely impact our ability to recover our investment in these assets. As of December 31, 2002, we have recorded regulatory assets that are currently subject to recovery in future rates of approximately $231.2 million. Of this amount, $153.2 million is a receivable for income tax benefits previously passed on to customers. The remainder of the regulatory assets are items that may give rise to stranded costs, including coal contract settlement costs, deferred plant costs and debt issuance costs.

In a competitive environment, we may not be able to fully recover our entire investment in Wolf Creek. We presently own 47% of Wolf Creek. We may also have stranded costs from an inability to recover our environmental remediation costs and long-term fuel contract costs in a competitive environment. If we determine that we have stranded costs and we cannot recover our investment in these assets, our future net income will be lower than our historical net income has been unless we compensate for the loss of such income with other measures.

EPA New Source Review

The Environmental Protection Agency (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

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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.

Nuclear Decommissioning

Decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund decommissioning. These plans are designed so that funds required for decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.

We accrue decommissioning costs over the expected life of the Wolf Creek generating facility. The accrual is based on estimated unrecovered decommissioning costs, which consider inflation over the remaining estimated life of the generating facility and are net of expected earnings on amounts recovered from customers and deposited in an external trust fund.

The KCC reviews our decommissioning fund financial plans in two phases. Phase one is the approval of the decommissioning study, the current year dollar amount and the future year dollar amount. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing its plans of how to fund the future year dollar amount for the pro rata share of the plant.

On February 25, 2002, we filed an application with the KCC to modify the funding schedule to reflect an assumed life of Wolf Creek through 2045 (see Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation”). This modification was granted on March 8, 2002. The filing reflects the current estimate in 1999 dollars of $221 million, but a future estimate in 2045 through 2054 of $1.28 billion. An updated decommissioning and dismantlement cost estimate was filed with the KCC on August 30, 2002. Costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied upon the site-specific, technical information developed in 1999, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. We anticipate a KCC order on the August 2002 decommissioning study in the second quarter of 2003. The actual decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

We will file a funding schedule to reflect the KCC’s order on the August 2002 decommissioning study by the end of the second quarter of 2003 and anticipate a KCC order on the funding schedule in the third quarter of 2003.

Decommissioning costs are currently being charged to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the March 8, 2002 funding schedule. Electric rates charged to customers provide for recovery of these decommissioning costs over the life of Wolf Creek as determined by the KCC through 2045. The NRC requires that funds to meet its decommissioning funding assurance requirement be in our decommissioning fund by the time our license expires in 2025. We believe that the KCC approved funding level will be sufficient to meet the NRC minimum financial assurance requirement. However, our

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results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.

Amounts expensed approximated $3.85 million in 2002 and will remain unchanged through 2044, subject to the August 2002 decommissioning cost review and revised funding schedule to be filed in the second quarter of 2003. These amounts are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.56%.

Our investment in the decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $63.5 million at December 31, 2002 and $66.6 million at December 31, 2001. The balance in the trust fund decreased from 2001 to 2002 due to the decline in the market value of equity securities held in the trust. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.

Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the standard, these liabilities will be recognized at fair value as incurred and capitalized and depreciated over the appropriate period as part of the cost of the related tangible long-lived assets. The adoption of SFAS No. 143 will not impact income. Any income effects are offset by a regulatory asset created pursuant to SFAS No. 71. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

We adopted SFAS No. 143 on January 1, 2003, which required us to recognize and estimate the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the present value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. These amounts were estimated based on the calculation guidelines of SFAS No. 143. We also established a regulatory asset for $64.0 million, which represents the accretion of the liability since 1985 and the increased depreciation expense associated with the increase in plant.

Related Party Transactions

Our cash management function, including cash receipts and disbursements, is performed by Westar Energy. An intercompany account is used to record net receipts and disbursements between KGE and Westar Energy and KGE and WR Receivables Corporation. The net amount payable from affiliates approximated $24.1 million at December 31, 2002 and the net amount receivable from affiliates approximated $17.3 million at December 31, 2001 as reflected in our consolidated balance sheets.

Westar Energy provides all employees we utilize. Certain operating expenses have been allocated to us from Westar Energy. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers, and/or other appropriate factors. We believe such allocation procedures are reasonable.

During the fourth quarter of 2001, we entered into an option agreement to sell an office building located in downtown Wichita, Kansas, to Protection One, a subsidiary of Westar Industries, which is a wholly owned subsidiary of Westar Energy for approximately $0.5 million. The sales price was determined by management based on three independent appraisers’ findings. This transaction was completed during June 2002. We recognized a loss of $2.6 million on this transaction, and we expected to realize annual operating cost savings of approximately $0.9 million. The cost savings will be treated as a regulatory liability in accordance with a March 26, 2002, KCC order. For the year ended December 31, 2002, we recorded $0.5 million in cost savings as a regulatory liability.

Termination of Shared Services Agreement

ONEOK, Inc. (ONEOK), an investment in which Westar Energy presently owns an approximate 27.5% interest, gave Westar Energy notice of termination effective December 2003 of a shared services agreement pursuant

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to which Westar Energy and ONEOK provide customer service functions to each other, including meter reading, customer billing and call center operations. Following termination, Westar Energy will allocate to us our portion of the expenses for providing these services internally. We expect termination of this agreement will increase our annual costs for these services by approximately $6 million to $7 million.

Hedging Activity

We use derivative financial and physical instruments to hedge a portion of our anticipated fossil fuel needs. At the time we enter into these transactions, we are unable to determine what the value will be when the agreements are actually settled.

In an effort to mitigate fuel commodity price market risk, Westar Energy and we jointly use hedging arrangements to reduce our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent upon the market prices and the extent and effectiveness of any hedging arrangements into which we enter.

See Note 5 of the Notes to Consolidated Financial Statements, “Financial Instruments, Energy Trading and Risk Management — Derivative Instruments and Hedge Accounting — Trading Activities” for detailed information regarding hedging relationships we entered into during the third quarter of 2001.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Price Risks

Our hedging and trading activities involve risks, including commodity price risk, interest rate risk and credit risk. Commodity price risk is the risk that changes in commodity prices may impact the price at which we are able to buy and sell electricity and purchase fuels for our generating units. These commodities have experienced price volatility in the past and can be expected to do so in the future. This volatility may increase or decrease future earnings. Interest rate risk is the risk of loss associated with movements in market interest rates. Credit risk is the risk of loss resulting from non-performance by a counterparty of its contractual obligations. We have exposure to credit risk and counterparty default through our retail and system trading activities. We maintain credit policies intended to reduce overall credit risk and actively monitor these policies to reflect changes and scope of operations. We employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees and standardized master netting agreements from counterparties that allow for some of the offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Results actually achieved from hedging and trading activities could vary materially from intended results and could materially affect our financial results depending on the success of our credit risk management efforts.

Commodity Price Exposure

We are exposed to commodity price changes and use derivatives for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service.

From 2001 to 2002, we experienced a 22% decrease in the average price per MWh of electricity purchased for utility operations. Purchased power market volatility could be greater than the average price decrease indicates. If we were to have a 10% increase in our purchased power price from 2002 to 2003, given the amount of power purchased for utility operations during 2002, we would have exposure of approximately $0.8 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices.

We use a mix of various fossil fuel types, including coal, natural gas and oil, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under

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long-term contract, which removes most of the price risk associated with this commodity type. During 2002, we experienced an approximate 4% decrease in our average cost for natural gas purchased for utility operations, or a decrease of $0.139 per MMBtu. We decreased our gas usage by 2.0 million MMBtu compared to the amount burned in 2001. Due to the volatility of natural gas prices, we have begun to increase our ability to switch to lower cost fuel types as the market allows. We expect that exposure to natural gas price changes will not be material in 2003 due to our natural gas hedge that has fixed the price of our gas through July 2004.

We use uranium to fuel our nuclear generating station and have on hand or under contract 100% of Wolf Creek’s uranium, uranium conversion and uranium enrichment needs for 2003. We have on hand or under contract 76% of the uranium and uranium conversion and 80% of the uranium enrichment required for operation of Wolf Creek through March 2008. The balance is expected to be obtained through spot market and contract purchases, which means we will be exposed to the price risk associated with these components.

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically from year to year based on the individual fuel’s availability, price, deliverability, unit outages and nuclear refueling. Our customers’ electricity usage could also vary dramatically year to year based on the weather or other factors.

Interest Rate Exposure

We had approximately $181.4 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2002, of which, $135.0 million has been irrevocably deposited with the bond trustee to provide for the repayment of an obligation. A 100 basis point change in the remainder of each debt series’ benchmark rate used to set the rate for such series would impact net income on an annualized basis by approximately $0.3 million after tax.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

SCHEDULES OMITTED

The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in our consolidated financial statements and schedules presented:

I, II, III, IV, and V.

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of

Kansas Gas and Electric Company

Topeka, Kansas

We have audited the accompanying consolidated balance sheets of Kansas Gas and Electric Company (the Company), a wholly-owned subsidiary of Westar Energy, Inc., as of December 31, 2002 and 2001, and the related consolidated statements of income and comprehensive income, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Kansas Gas and Electric Company as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, on January 1, 2001 the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.

DELOITTE & TOUCHE LLP

Kansas City, Missouri

April 15, 2003

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KANSAS GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)