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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

x ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE     

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     

SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 1-3523

Westar Energy, Inc.

(Exact name of registrant as specified in its charter)

818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300

(Address, including Zip code and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to section 12(b) of the Act:

Securities registered pursuant to section 12(g) of the Act:

Preferred Stock, 4 ¹/2% Series, $100 par value

(Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

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

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $1,170,717,860 at June 30, 2003.

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

DOCUMENTS INCORPORATED BY REFERENCE:

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” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning:

What happens in each case could vary materially from what we expect because of such things as:

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These lists are not all-inclusive because it is not possible to predict all 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 are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

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PART I

ITEM 1. BUSINESS

GENERAL

Westar Energy, Inc., a Kansas corporation incorporated in 1924, is the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc. alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 644,000 customers in Kansas. Westar Energy provides these services in northeastern Kansas, including the Topeka, Lawrence, Manhattan, Salina and Hutchinson metropolitan areas. Kansas Gas and Electric Company (KGE), our wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the Wichita metropolitan area. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas, and a 47% interest in Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek.

Westar Industries, Inc. (Westar Industries), our wholly owned subsidiary, owned an 87% interest in Protection One, Inc. (Protection One), a publicly traded company that provides monitored security services, and our investment in Protection One Europe. Westar Industries now owns other non-material investments. We sold our interest in Protection One on February 17, 2004, and we sold our interest in Protection One Europe on June 30, 2003. In 2003, we classified our interests in monitored security businesses as discontinued operations. See Note 5 of the Notes to Consolidated Financial Statements, “Discontinued Operations,” for additional information about the classification of our monitored security businesses as discontinued operations.

SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2003

KCC Orders and Debt Reduction Plan

On February 6, 2003, we filed a debt reduction plan (the Debt Reduction Plan) with the Kansas Corporation Commission (KCC) in response to the KCC’s order that would have required us to reduce debt to $1.67 billion by August 1, 2003. In the Debt Reduction Plan, we outlined our plans for paying down debt and simplifying our business. The Debt Reduction Plan calls for the sale of our non-utility assets, including our interests in Protection One and Protection One Europe and our minority equity interest in ONEOK, Inc. (ONEOK), a diversified energy company. As part of the Debt Reduction Plan, we reduced our quarterly dividend on our common stock 37% to $0.19 per share beginning with the dividend paid April 1, 2003.

On July 21, 2003, we entered into a Stipulation and Agreement (Stipulation) with the KCC staff and other intervenors in the docket considering the Debt Reduction Plan. The KCC issued an order approving the Stipulation on July 25, 2003. The principal terms of the Stipulation are as follows:

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In August 2003, we began ratably recording a regulatory liability for the rebates that will be paid to customers in 2005 and 2006. Accordingly, as of December 31, 2003, we have recorded a regulatory liability of $3.5 million for revenue to be refunded, which is included in other liabilities on our consolidated balance sheets.

Also in August 2003, Westar Industries transferred to Westar Energy all of its remaining stock in ONEOK and all of its cash in excess of $2.0 million. Westar Industries has continued to transfer cash in excess of $2.0 million in subsequent months. These transfers are intercompany transactions that do not result in any change to the amounts reported on our consolidated financial statements. In addition, in accordance with a KCC order, an intercompany receivable in the amount of $710.5 million from Westar Industries was reclassified as an investment in Westar Industries. This intercompany transaction is eliminated in consolidation.

In 2003, we reduced our debt by $965.7 million primarily through use of the proceeds from the sale of our ONEOK stock and through the retirement of $135.0 million of debt that was economically defeased in 2002. With the closing of the sale of our interest in Protection One on February 17, 2004, we received proceeds of $122.2 million, which will also be used to reduce debt. We plan to issue $100 million to $250 million of equity during 2004.

Sale of ONEOK Stock Investment

We sold our ONEOK stock investment in multiple transactions in February, August and November 2003 for total proceeds of $801.8 million, net of transaction costs. We recorded a pre-tax gain of $99.3 million. We used the net proceeds for repayment of our outstanding debt.

Discontinued Operations — Sale of Protection One and Protection One Europe

In 2003, we classified our monitored security businesses as discontinued operations. This is reflected in the accompanying consolidated financial statements. We also reclassified all historical periods to conform with this reclassification. These reclassifications were required by generally accepted accounting principles (GAAP) as a result of our board of directors’ approval of the Debt Reduction Plan. The amounts associated with our discontinued operations are included in our “Other” segment. See Note 29 of the Notes to Consolidated Financial Statements, “Segments of Business,” for further information relating to our “Other” segment.

We sold our interest in Protection One Europe on June 30, 2003. The sale resulted in a $58.7 million reduction in our consolidated debt level from the buyer’s assumption of $48.2 million of Protection One Europe debt that was included in our consolidated financial statements and the use of $10.5 million of cash proceeds to pay down debt.

On December 23, 2003 we signed a definitive agreement to sell our interests in Protection One to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). The transaction did not include the sale of our Protection One 7 ³/8% senior notes due August 15, 2005 in the face amount of $26.6 million.

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On February 17, 2004, we closed the sale of the Protection One stock owned by Westar Industries to Quadrangle and assigned to Quadrangle the senior credit facility between Westar Industries and Protection One, which had an outstanding balance at December 31, 2003 and at closing of $215.5 million. At closing, we received proceeds of $122.2 million. We could receive up to an additional $24.2 million of cash contingent on Quadrangle meeting post-closing investment objectives and an additional $15.0 million of cash upon our making additional payments to Protection One under a tax sharing agreement between us and Protection One. These contingent payments depend upon post-closing facts and circumstances and may not materialize in whole or in part and, if payable, may not be paid for a significant period of time after closing. The net cash proceeds from the transaction will be used to reduce debt.

Protection One has been part of our consolidated tax group since 1997. During that time, we have reimbursed Protection One for current tax benefits attributable to Protection One used in our consolidated tax return under the terms of a tax sharing agreement. Following the sale of our Protection One common stock on February 17, 2004, Protection One is no longer a part of our consolidated tax group. We and Protection One did not formally terminate our tax sharing agreement and, based on discussions with Protection One and its counsel, there are several areas of potential dispute between us regarding our obligations under the terms of the tax sharing agreement. The most material of these potential disputes involve (i) the proper treatment under the tax sharing agreement of tax obligations or benefits arising out of the transaction in which we sold our interest in Protection One, including the impact of the cancellation of indebtedness income generated by the assignment of a credit agreement for less than the full amount outstanding under the credit agreement at closing on future payments if any, to Protection One, (ii) whether any payments will be due to Protection One as a result of any tax benefits that may arise from a decision by us in the future to elect to treat the sale of our Protection One stock as a sale of assets under the Internal Revenue Code and (iii) whether payments due Protection One when we are subject to alternative minimum tax should be calculated at the alternative minimum tax rate of 20% or the normal statutory rate of 35%. Because of these potential disputes, we have provided for these matters in our consolidated financial statements. We nevertheless believe that we have strong positions with respect to each of these items and will aggressively pursue our positions. If we prevail, we may realize significant additional benefits, which may reduce future cash taxes and increase our reported net income.

Before classifying our monitored services businesses as discontinued operations, we were unable to record a tax benefit for a significant portion of the goodwill impairment and amortization charges and losses of our monitored services businesses recorded in prior years. Upon classification as discontinued operations, GAAP requires the current recognition of any tax benefit that will be realized in the foreseeable future, net of any required valuation allowance. We estimate the tax benefits associated with the capital loss on the sale of Protection One and the assignment of the senior credit facility with Protection One to be approximately $327.7 million. Based on the sale of our ONEOK investment and current projections of taxable income, we estimate that it is likely that we will be able to realize approximately $93.8 million of these tax benefits. Therefore, we have recorded a $233.9 million valuation allowance for that portion of the tax benefit that we estimate may be unrealizable in the foreseeable future.

With discontinued operations accounting, we were required to estimate the net realizable proceeds from the sale of our monitored services businesses. We used actual sale proceeds to calculate the loss from discontinued operations related to Protection One Europe, which resulted in a write off of $13.5 million. When we initially classified Protection One as discontinued operations in the first quarter of 2003, our estimate of the net realizable proceeds from the sale of Protection One was based on an independent appraisal. At that time, we recorded a write down of $41.6 million on our Protection One investment. We updated our estimates in the third quarter of 2003 based on then existing bids from potential buyers and took an additional write down of $165.6 million. Upon signing the definitive agreement with Quadrangle on December 23, 2003, we reduced our estimated net realizable proceeds by an additional $38.5 million to reflect actual proceeds, and wrote off that amount in the fourth quarter of 2003.

Call Option

In August 1998, we entered into a call option with an investment bank related to the issuance of $400.0 million of our 6.25% senior unsecured notes. These notes were putable and callable on August 15, 2003 (the putable/callable notes).

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In the second quarter of 2003, we purchased a call option at a cost of $65.8 million, which locked in the settlement cost associated with the August 1998 call option. The outstanding options were settled and the related notes were retired in August 2003. For the year ended December 31, 2003, we recognized a loss related to the putable/callable notes of $21.5 million, which includes a loss of $14.2 million associated with the settlement of the call options.

Special Committee Investigation

In September 2002, our board of directors appointed a special committee of directors to investigate matters related to a federal grand jury subpoena served on us by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of our corporate aircraft and our annual shareholder meetings. The scope of the special committee’s investigation was expanded to cover other matters that were the subject of additional United States Attorney’s Office subpoenas served on us and certain of our employees. These matters included executive compensation arrangements with David C. Wittig, our former chairman of the board, president and chief executive officer, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, and other former and present officers; the proposed rights offering of Westar Industries stock that was abandoned; and the company in general. The investigation also included matters that were the subject of a Securities and Exchange Commission (SEC) inquiry into the restatement of our first and second quarter 2002 consolidated financial statements and disclosures in our proxy statements concerning personal aircraft use by former officers and the payment of a bonus to Mr. Wittig in 2002. The special committee completed its investigation and publicly released a report on May 14, 2003 concerning the conclusions and recommendations reached as a result of the investigation. The investigation did not result in adjustments to our previously filed financial statements.

ELECTRIC UTILITY OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 346,000 customers in northeast Kansas, including the communities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. KGE supplies electric energy at retail to approximately 298,000 customers in south-central and southeastern Kansas, including the city of Wichita. We classify our retail customers as residential, commercial and industrial as defined in our tariffs. We also supply electric energy at wholesale to the electric distribution systems of 55 Kansas cities and four rural electric cooperatives. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, our energy marketing operations purchase and sell wholesale electricity in areas outside our historical service territory.

Generation Capacity

We have 5,904 megawatts (MW) of generating capacity, of which 2,596 MW, including Wolf Creek, is owned by KGE. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.

Our aggregate 2003 peak system net load of 4,655 MW occurred on August 21, 2003. This is also our all-time peak system net load. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 18% above system peak responsibility at the time of the peak. We do not anticipate needing additional generating capacity through at least 2006.

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

Fossil Fuel Generation

Fuel Mix

The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the lesser quantity of the fuel it takes to produce electricity. The quantity of heat consumed during the generation of electricity is measured in millions of Btu (MMBtu).

Based on MMBtus, our 2003 actual fuel mix was 81% coal, 14% nuclear and 5% natural gas, oil or diesel fuel. We expect that our fuel mix in 2004 will have a higher percentage of nuclear usage since 2004 is not a refueling year at Wolf Creek. Our fuel mix fluctuates with the operation of Wolf Creek, as discussed below under “— Nuclear Generation,” fluctuations in 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 have an aggregate capacity of 2,213 MW, of which we own an 84% share, or 1,859 MW. We have a long-term coal supply contract with Amax Coal West, Inc., a subsidiary of RAG America Coal Company, to supply coal to Jeffrey Energy Center from mines located in the Powder River Basin (PRB) in Wyoming. All of the coal used at Jeffrey Energy Center is purchased under this contract. 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 renegotiated every five years to provide a fixed price at current market prices. The first year affected by this repricing mechanism was 2003. The renegotiated price increased the cost of coal received in 2003 by approximately $3.0 million over the cost in the prior year.

The coal supplied to Jeffrey Energy Center during 2003 was surface mined and had an average Btu content of approximately 8,430 Btu per pound and an average sulfur content of 0.48 lbs/MMBtu (see “— Environmental Matters” for a discussion of sulfur content). The average delivered cost of coal burned at Jeffrey Energy Center during 2003 was approximately $1.21 per MMBtu, or $20.53 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 1,362 MW, of which we own a 50% share, or 681 MW. LaCygne 1 uses a blended fuel mix containing approximately 85% PRB coal and 15% Kansas/Missouri coal. LaCygne 2 uses PRB coal. The operator of LaCygne, Kansas City Power & Light Company (KCPL), administers the coal and coal transportation contracts. All of the LaCygne 1 and LaCygne 2 PRB coal is supplied through fixed price contracts through 2005 and is transported under KCPL’s Omnibus Rail Transportation Agreement with the BNSF and Kansas City Southern Railroad through December 31, 2010. The LaCygne 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers.

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The PRB coal supplied to LaCygne 1 and LaCygne 2 during 2003 had an average Btu content of approximately 8,658 Btu per pound and an average sulfur content of 0.38 lbs/MMBtu. During 2003, the average delivered cost of all coal burned at LaCygne 1 was approximately $0.85 per MMBtu, or $15.03 per ton. The average delivered cost of coal burned at LaCygne 2 was approximately $0.77 per MMBtu, or $13.17 per ton.

Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 795 MW. We have a coal supply contract ending in December 2004 with Kennecott Coal Sales Company to supply PRB coal to Lawrence and Tecumseh Energy Centers. Approximately 62% of the coal used at these energy centers on an annual basis is purchased under this contract with the remainder purchased on the spot market. In 2003, the coal supplied to Lawrence and Tecumseh Energy Centers had an average Btu content of approximately 8,820 Btu per pound and an average sulfur content of 0.41 lbs/MMBtu. During 2003, the average delivered cost of all coal burned in the Lawrence units was approximately $1.01 per MMBtu, or $17.87 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.02 per MMBtu, or $17.95 per ton.

The coal supplied to Lawrence and Tecumseh Energy Centers is transported from Wyoming by the BNSF railroad under a contract ending in December 2004. We expect to extend this contract through December 2006. We have received proposals for contracts to supply coal to Lawrence and Tecumseh Energy Centers for various terms and prices beyond 2005. We anticipate entering into one or more contracts by the end of the first quarter of 2004. Spot market coal may or may not be a part of the supply plan for years 2005 and beyond.

General: We have entered into all of our coal contracts in the ordinary course of business and do not believe we are substantially dependent on 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. Because 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. Although several rail carriers are capable of serving the coal mines from where our coal originates, 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 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 disruption of our business, although the cost of transporting coal could increase.

Natural Gas

We use natural gas either as a primary fuel or as a start-up/secondary fuel, depending on market prices, in our Gordon Evans, Murray Gill, Neosho, Abilene and Hutchinson Energy Centers, in the gas turbine units at our Tecumseh generating station and in the combined cycle units at the State Line facility. Natural gas is also used as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. Natural gas for all facilities is purchased in the short-term spot market, which supplies our facilities with a flexible natural gas supply as necessary to meet operational needs. During 2003, we purchased 3.2 million MMBtu of natural gas on the spot market for a total cost of $16.3 million. Natural gas accounted for approximately 1% of our total fuel burned during 2003.

If natural gas prices are higher than the amount we are able to recover through our retail rates, we may be exposed to the increased natural 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 and by using other pricing techniques available to us, such as purchasing derivative contracts. To recover increased natural gas costs in excess of the cost included in retail rates, we would have to make a rate filing with the KCC or request a recovery mechanism through the KCC, which could be denied in whole or in part. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Natural gas transportation for the Abilene and Hutchinson Energy Centers is maintained with Kansas Gas Service Company, a division of ONEOK. This contract expires April 30, 2004. We expect that we will be able to renegotiate this contract with similar terms. We meet a portion of our natural gas transportation requirements for the

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Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. All of the natural gas transportation requirements for the State Line facility are met through a firm natural gas transportation agreement with Southern Star Central Pipeline. The firm transportation agreements that serve the Gordon Evans, Murray Gill, Lawrence and Tecumseh Energy Centers extend through April 1, 2010. The agreement for the Neosho and State Line facilities extends through June 1, 2016.

Oil

Our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn oil in addition to natural gas once the facilities have been started with natural gas. We use oil as an alternate fuel when economical or when interruptions to natural gas supply make it necessary. Because oil during 2003 was more economical than natural gas, we used oil as the primary fuel in these generating facilities for most of 2003. In addition, over the past few years, we have been able to sell more power at wholesale during the winter months when oil has typically been more economical than natural gas. During 2003, we purchased 10.3 million MMBtu of oil for a total cost of $33.5 million. Oil accounted for approximately 3% of our total fuel burned during 2003.

Oil is also used as a start-up fuel at some of our generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in the diesel generators. Oil is obtained by spot market purchases and longer-term contracts. We maintain quantities in inventory that we believe will meet our fuel switching needs to facilitate economic dispatch of power, for emergency requirements and to protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to burn.

Other Fuel Matters

Our contracts to supply fuel for our coal-fired and natural gas-fired generating units, with the exception of Jeffrey Energy Center, 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. In 2001, we designated certain derivative contracts entered into for natural gas as a cash flow hedge under Statement of Financial Accounting Standards (SFAS) No. 133. We discontinued accounting for these derivative contracts as a cash flow hedge at the end of 2003. Since we currently do not use hedge accounting for any financial instruments, any changes in the fair value of these instruments are recognized currently in earnings. Due to the volatility of the fuel 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 the retail customers within our service territory. Factors that could cause us to purchase power for retail customers include generating plant outages, prices for wholesale energy, extreme weather conditions, growth,

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and other factors. If we were unable to generate an adequate supply of electricity for our retail customers, we would purchase power in the wholesale market to the extent it is available, subject to transmission constraints, and/or implement curtailment or interruption procedures as permitted by our tariffs and terms and conditions of service.

Nuclear Generation

Wolf Creek

Wolf Creek is a 1,166 MW nuclear power plant located near Burlington, Kansas. Wolf Creek began operation in 1985. KGE owns a 47% interest in Wolf Creek, or 548 MW, which represents 9.3% of our total generating capacity. KCPL also owns a 47% interest in Wolf Creek and a 6% interest is owned by a group of Kansas electric cooperatives. Wolf Creek is operated by WCNOC, a corporation owned by the co-owners of Wolf Creek. The co-owners pay the operating costs of WCNOC equal to their percentage ownership in Wolf Creek. WCNOC has approximately 1,000 employees.

Over the last three years, Wolf Creek contributed an average of 16% of our annual megawatt hours (MWh) generated while operating at an average capacity factor of approximately 92%. Wolf Creek has the lowest fuel cost per MWh generated of any of our generating units. An extended or unscheduled shutdown of Wolf Creek could have a substantial adverse effect on our business, financial condition and consolidated results of operations because of higher replacement power and other costs and reduced amounts of power to sell at wholesale.

Fuel Supply

Wolf Creek has on hand or under contract 84% of its uranium needs and 100% of its uranium conversion needs for 2004. In addition, 94% of the uranium and 100% of the uranium conversion required for operation of Wolf Creek through October 2009 is under contract. The balance of the 2004 uranium requirement is expected to be purchased on the spot market.

The owners have under contract 100% of the uranium enrichment required to operate Wolf Creek through March 2008. Fabrication requirements are under contract through 2024.

All uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered into in the ordinary course of business, and Wolf Creek ordinarily is not substantially dependent on these agreements. However, contraction and consolidation among suppliers of these commodities and services, coupled with recent temporary shutdowns of some production facilities of two of the suppliers, have introduced some uncertainty as to Wolf Creek’s ability to replace, if necessary, some of these contracts. We believe this potential problem is common to the nuclear industry. Accordingly, in the event the affected contracts were required to be replaced, Wolf Creek’s management believes that the industry and government would arrive at a solution to minimize disruption of the nuclear industry’s operations, including Wolf Creek’s operations.

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

Radioactive Waste Disposal

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays the DOE a quarterly fee for the future disposal of spent nuclear fuel. The fee is one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. These disposal costs are included in the 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.

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In mid-2002, Congress passed and the President signed a resolution approving 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. 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.

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.

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 the Compact Commission, which is responsible for causing a new disposal facility to be developed within one of the member states. The Compact Commission selected Nebraska as the host state for the disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project. Our net investment in the Compact is approximately $7.4 million.

In December 1998, the Nebraska agencies responsible for considering the developer’s license application denied the application. The license applicant sought a hearing on the license denial, but a United States District Court indefinitely delayed proceedings related to the hearing. Most of the utilities that had provided the project’s pre-construction financing (including WCNOC) filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the court entered a $151.4 million judgment, about one-third of which constitutes prejudgment interest, in favor of the Compact Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. On Nebraska’s appeal, the 8th Circuit, United States Court of Appeals, upheld the District Court’s decision in February 2004. Nebraska has sought further appellate court review of the decision.

By late summer 2004, Nebraska should no longer be a member of the Compact as a result of either its notice of voluntary withdrawal given in 1999 or the Compact Commission’s 2003 revocation of the state’s membership. Neither Nebraska’s withdrawal from the Compact nor the Compact Commission’s revocation of Nebraska’s membership in the Compact will of themselves nullify the site license proceeding.

Outages

Wolf Creek operates on an 18-month refueling and maintenance outage schedule that permits operations during every third calendar year without interruption for a refueling outage. Wolf Creek was shut down for 45 days in 2003 for its 13th scheduled refueling and maintenance outage, which began on October 18, 2003 and ended on December 2, 2003. During the outage, a complete inspection of the reactor vessel head indicated no corrosion or other problems. During outages, our electric demand is met primarily by our fossil-fueled generating units and by purchasing power according to the most economical pricing and availability. As provided by the KCC, we amortize the incremental maintenance costs incurred for planned refueling outages evenly over the unit’s operating cycle, normally 18 months. Wolf Creek is scheduled to be taken off-line in the spring of 2005 for its 14th refueling and maintenance outage.

An extended or unscheduled shutdown of Wolf Creek could have a substantial adverse effect on our business, financial condition and consolidated results of operations because of higher replacement power and other costs and reduced amounts of power to sell at wholesale. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or other concerns.

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Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with 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 nuclear decommissioning. These plans are designed so that funds required for nuclear decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.

We accrue nuclear decommissioning costs over the expected life of the Wolf Creek generating facility. The amount we accrue is based on the decommissioning costs approved by the KCC to be included in rates. Decommissioning costs that are recovered in rates are deposited in an external trust fund.

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

An updated nuclear decommissioning and dismantlement cost estimate was filed with the KCC on August 30, 2002. Estimated costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied on site-specific, technical information, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s nuclear decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220.0 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

The KCC issued an order on April 16, 2003 approving the August 2002 nuclear decommissioning study for Wolf Creek. On June 2, 2003, we filed a funding schedule with the KCC to reflect the KCC’s April 16, 2003 order. On October 10, 2003, the KCC approved the funding schedule as filed without any change to our funding obligation.

Nuclear 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 funding schedule in the KCC’s October 13, 2003 order. Electric rates charged to customers provide for recovery of these nuclear decommissioning costs over the life of Wolf Creek as determined by the KCC through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear 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 consolidated results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.

Nuclear decommissioning amounts expensed in 2003 approximated $3.9 million. The amounts collected are deposited in an external trust fund. The average after-tax expected return on trust assets is 5.7%.

Our investment in the nuclear decommissioning fund is recorded at fair value, including reinvested earnings. It approximated $80.1 million at December 31, 2003 and $63.5 million at December 31, 2002. Trust fund earnings accumulate in the fund balance and increase the recorded decommissioning liability.

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, patrolling of company property, restricting access to our properties and implementing emergency training and response procedures.

The NRC has issued orders to all nuclear plants that make our current security measures mandatory. The orders also impose new security requirements at United States nuclear power plants. Wolf Creek has complied with these requirements. There are additional requirements related to homeland security in the NRC orders that are required to be completed by October 29, 2004. Wolf Creek is working to meet that compliance deadline.

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Competition and Deregulation

Electric utilities have historically operated in a rate-regulated environment. The Kansas Legislature and the KCC took no action on deregulation in 2003 or 2002, and we expect no action to be taken in the near future. The Federal Energy Regulatory Commission (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 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted the FERC to order electric utilities to allow third parties to use their transmission systems to sell electric power to wholesale customers. In 1992, we agreed to open access of our transmission system for wholesale transactions. The FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, the 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.

Southwest Power Pool

We are a member of the Southwest Power Pool (SPP). On October 15, 2003, the SPP filed an application with the FERC to be granted RTO status. The FERC granted SPP’s application on February 10, 2004 subject to the SPP fulfilling certain specified requirements. If the SPP meets the requirements of the February 10, 2004 Order and obtains RTO status, we expect to be a member and turn operational control of our transmission system over to the SPP RTO under its membership agreement and applicable tariff. If approved, the SPP RTO will operate our transmission system as part of an interconnected transmission system across eight states. The SPP RTO will collect revenues attributable to the use of each member’s transmission system. Members and transmission customers will be able to transmit power purchased, generated for sale or bought for resale in the wholesale market throughout the entire SPP RTO system. We believe each transmission owner generally retains the transmission capacity needed to serve its existing retail customers. Any additional transmission capacity will be sold on a first come/first served non-discriminatory basis. All transmission customers will be charged uniform rates for use of the transmission system, including entities that may sell power inside our certificated service territory. We do not expect that our participation in the SPP RTO will have a material effect on our operations; however, there will be increased costs due to establishment of the RTO and associated markets. At this time, it is difficult to quantify these costs because these market systems have not been fully designed and there are many implementation issues that remain unresolved, such as regulatory jurisdiction over bundled transmission rates. It is anticipated that these costs will be recovered through future increases in RTO charges.

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 the FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. We are exempt as a public utility holding company pursuant to the Public Utility Holding Company Act of 1935 from all provisions of that Act, except Section 9(a)(2), which relates to the acquisition of the securities of other utilities.

We will file a rate case with the KCC by May 1, 2005, based on a test year consisting of the 12 months ending December 31, 2004. Prior to May 1, 2005, we will not make a filing to increase our Kansas jurisdictional electric rates. Certain other parties have agreed not to file a rate complaint or motion for us to show cause why our rates should not be reduced.

Effective January 4, 2004, the United States government enacted legislation that revised the “Hours of Service” regulations that govern the length of time that drivers may operate vehicles and the length of time they must be off-duty. This legislation was designed to reduce accidents related to driver fatigue. Until September 2004, electric utilities are exempt from implementing these changes. During restoration of electric service after a severe storm or other major power outages, we have to obtain a declaration of a state of emergency in order to gain an

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exception to these rules. The exception would permit employees who are required to restore electric power to operate equipment for extended hours without the required off-duty time. The impact of this legislation could affect customer service and could result in increased operating costs if we have to hire additional employees or lengthen electric service outage periods.

On February 10, 2004, the National Electric Reliability Council (NERC) issued its anticipated reliability improvement initiatives that stem from investigations of the August 14, 2003 blackout in the Eastern United States. These initiatives will impact our operations in a number of ways, such as, system relay protection, vegetation management and operator training. NERC and the ten operating regions in the United States, including the SPP, are working together to determine what operating policies and planning standards changes are necessary to achieve the NERC’s goals. Although it is difficult to ascertain potential costs at this time, it is likely that our annual capital and maintenance expenditure requirements will increase over the historic trends.

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

Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. These laws and regulations primarily relate to discharges into the air and air quality, discharges of effluents into water and the use of water, and the handling and disposal of hazardous substances and wastes. These laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for our new, existing or modified facilities. If we fail to comply with such laws and regulations, we could be fined or otherwise sanctioned by regulators. In addition, under certain laws, we could be responsible for costs relating to contamination at our current and former facilities or at third-party waste disposal sites. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations.

Environmental laws and regulations affecting power plants are overlapping, complex, subject to changes in interpretation and implementation and have tended to become more stringent over time. Although we believe that we can recover in rates costs relating to compliance with such laws and regulations, there can be no assurance that we will be able to recover all or any such increased costs from our customers or that our business, consolidated financial condition or results of operations will not be materially and adversely affected as a result of costs to comply with such existing and future laws and regulations.

Air Emissions

The Clean Air Act, state laws and implementing regulations impose, among other things, limitations on major pollutants, including SO2, particulate matter and nitrogen oxides (NOx).

Certain Kansas Department of Health and Environment regulations applicable to our generating facilities prohibit the emission of SO2 in excess of certain levels. In order to meet these standards, we use low-sulfur coal, fuel oil and natural gas and have equipped our generating facilities with pollution control equipment.

In addition, we must comply 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 in order to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II SO2 and NOx requirements.

Title IV of the Clean Air Act created an SO2 allowance and trading program as part of the federal acid rain program. Under the allowance and trading program, the United States Environmental Protection Agency (EPA) allocated annual SO2 emissions allowances for each affected emitting unit. An SO2 allowance is a limited authorization to emit one ton of SO2 during a calendar year. At the end of each year, each emitting unit must have enough allowances to cover its emissions for that year. Allowances are tradable so that affected units that are anticipated to emit SO2 in excess of their allowances may purchase allowances from affected units that are anticipated to emit SO2 in an amount less than their allowances. Because of strong demand for generation during

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2002 and 2003, we consumed more SO2 allowances than were allocated to us by the EPA. We made up the shortfall by buying allowances. In 2004 and future years, we may purchase SO2 allowances as necessary in order to meet the acid rain requirements of the Clean Air Act.

On January 30, 2004, the EPA published two proposed air quality rules referred to as the “Interstate Air Quality Rule” and the “Utility Mercury Reduction Rule” that, if adopted, would impact our operations. In an attempt to address the impact of interstate transport of air pollutants on downwind states, the proposed Interstate Air Quality Rule would require reductions of SO2 and NOx in certain states, including Kansas, in two separate phases. The first reductions would be required in 2010 and the second in 2015.

The proposed Utility Mercury Reduction Rule sets out two approaches for requiring subject power plants to control mercury and nickel emissions. The first option, a traditional command and control approach, would require subject plants to meet Hazardous Air Pollutant emissions standards for mercury and nickel based on the application of maximum available control technology. The second option would establish standards of performance limiting mercury and nickel emissions, and include a “cap and trade” program for mercury emissions. The EPA is expected to issue its final rule in 2005. New requirements for reductions of nickel emissions will be applicable only to our generating facilities that burn a significant amount of heavy fuel oil. Based on currently available information, we cannot estimate our costs to comply with these two proposed rule changes, but these costs could be material.

We may be required to further reduce emissions of SO2, NOx, particulate matter, mercury and carbon dioxide (CO2) as a result of various other current or pending laws, including, in particular:

Based on currently available information, we cannot estimate our costs to comply with these proposed laws, but such costs could be material.

EPA New Source Review

The EPA is conducting numerous investigations nationwide to determine whether modifications at coal-fired power plants are subject to New Source Review requirements or New Source Performance Standards under Section 114(a) of the Clean Air Act (Section 114). These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could have reasonably been expected to result in a significant net increase in emissions. The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to remove emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

The EPA has requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.

We are in discussions with the EPA concerning this matter but are unable to predict whether the EPA will take further enforcement action. We will attempt to reach a settlement agreement with the EPA. However, if a settlement cannot be reached, the EPA could refer the matter to the United States Department of Justice for it to consider whether to pursue an enforcement action. If we are required to pay any fines or penalties or update or install emissions controls at Jeffrey Energy Center or the other coal-fired plants or take other remedial action, these costs could be material. We believe that costs related to updating or installing emissions controls would qualify for recovery through rates. If we are assessed a penalty as a result of the EPA’s allegation, the penalty could be material and may not be recovered in rates.

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Manufactured Gas Sites

We have been associated with a number of former manufactured gas sites located in Kansas and Missouri that may contain coal tar and other potentially harmful materials.

We and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Through December 31, 2003, the costs incurred for preliminary site investigation and risk assessment have been minimal. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the Kansas sites, our liability for twelve of the Kansas sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three Kansas sites. With respect to two of those sites, we are currently either conducting or completing remediation activities and, with respect to the third site, we will begin investigation activities in the near future.

Our liability for our former manufactured gas sites in Missouri is limited by an environmental indemnity agreement with Southern Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our future liability for these sites is capped at $7.5 million and terminates in 2009.

Solid Waste Landfills

We have operating solid waste landfills at Jeffrey Energy Center, Tecumseh Energy Center and Lawrence Energy Center for the single purpose of disposing of coal combustion waste material. Additionally, there is one retired landfill at each of the Lawrence and Neosho Energy Centers. All landfills are permitted by the KDHE. The operating landfill at Lawrence Energy Center is projected to be full by 2007 requiring us to permit and construct a new landfill at this site. It is anticipated that the lead-time for permitting a new landfill may be significant. We began the process of obtaining this permit in late 2003 but can offer no assurance as to when or if we will obtain the permit.

SEGMENT INFORMATION

Financial information with respect to business segments is set forth in Note 29 of the Notes to Consolidated Financial Statements, “Segments of Business,” and is incorporated herein by reference.

GEOGRAPHIC INFORMATION

Geographic information is set forth in Note 29 of the Notes to Consolidated Financial Statements, “Segments of Business,” and is incorporated herein by reference.

EMPLOYEES

As of February 29, 2004, we had approximately 2,000 employees. Our current contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers extends through June 30, 2005. The contract covered approximately 1,200 employees as of February 29, 2004.

ACCESS TO COMPANY INFORMATION

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

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RISK FACTORS

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the performance of our customers. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Our Revenues Depend Upon Rates Determined by the KCC

The KCC regulates many aspects of our business and operations, including the retail rates that we may charge customers for electric service. Our retail rates are set by the KCC using a cost-of-service approach that takes into account our historical operating expenses, our fixed obligations and recovery of our capital investments, including potentially stranded obligations. Using this approach, the KCC sets rates at a level calculated to recover such costs, adjusted to reflect known and measurable changes, and a permitted return on investment. Other parties to a rate case or the KCC staff may contend that our current rates or rates proposed in the rate case are excessive. In July 2003, we entered into a Stipulation that requires us to file a rate case, which may or may not include a request for a change in rates, by May 1, 2005 and to pay customer rebates of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. We agreed to the Stipulation and the required rebates to resolve matters related to the approval of our Debt Reduction Plan in a KCC proceeding, including assertions by some parties in the proceeding that our rates are excessive. The rates permitted by the KCC in the rate case will determine our revenues for the succeeding periods and may have a material impact on our consolidated earnings, cash flows and financial position, as well as our ability to maintain our common stock dividend at current levels or to increase our dividend in the future. We are unable to predict the outcome of the rate case.

Some of Our Costs May not be Fully Recovered in Retail Rates

Our rates, once established by the KCC, remain fixed until changed in a subsequent rate case. We may at any time elect to file a rate case to request a change in our rates or intervening parties may request that the KCC review our rates for possible adjustment, subject to any limitations that may have been ordered by the KCC. Earnings could be reduced to the extent that increases in our operating costs increase more than our revenues during the period between rate cases, which may occur because of maintenance and repair of plants, fuel and purchased power expenses, employee or labor costs, inflation or other factors.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity requires the use of expensive and complicated equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must acquire power from others at unpredictable cost in order to supply our customers and perform our contractual agreements. This can increase our costs materially and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. These factors, as well as weather, interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.

Non-Investment Grade Credit Ratings May Increase Our Borrowing Costs

We are highly leveraged. At December 31, 2003, we had outstanding senior indebtedness of approximately $2.3 billion, consisting primarily of $1.4 billion of first mortgage bonds and debt secured by first mortgage bonds and $869.5 million of unsecured debt, including capital leases. First mortgage bonds are secured by a lien on substantially all of our utility property. A substantial portion of our senior debt is rated “less than investment grade” by the major rating services, which makes our cost of borrowing higher than it is for better rated companies. We have agreed with the KCC that we will reduce the proportion of our capital structure represented by debt from the December 31, 2003 level such that common equity becomes no less than 40% of our capitalization by December 31, 2004, but this may not cause the rating agencies to give us an “investment grade” rating. There can be no assurance that our ratings will be raised before we are required to refinance certain of our indebtedness that matures during the next few years.

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We May Have a Material Financial Exposure Under the Clean Air Act and Other Environmental Regulations

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements under the Clean Air Act. This notification was delivered as part of an investigation by the EPA regarding maintenance activities that have been conducted since 1980 at the three coal-fired plants that we operate. If this matter is not resolved with the EPA, it may be referred to the United States Department of Justice for it to consider whether to pursue an enforcement action. The remedy for a violation could include fines and penalties and an order to install new emission control systems, the cost of which could be material.

Our activities are subject to stringent environmental regulation by federal, state, and local governmental authorities. These regulations generally involve effluents into the water, emissions into the air, the use of water, and hazardous substance and waste handling, remediation and disposal, among others. Congress also may consider legislation and the EPA may propose new regulations or change existing regulations that could require us to further restrict or reduce certain emissions at our plants. Legislation, proposed regulations or changes in regulations, if adopted, could impose additional costs on the operation of our power plants. Although we generally recover such costs through our rates, there can be no assurance that we would be able to recover all or any increased costs relating to compliance with environmental regulations from our customers or that our business, consolidated financial condition or results of operations would not be materially and adversely affected. We have made and will continue to make capital and other expenditures to comply with environmental laws and regulations. There can be no assurance that such expenditures will not have a material adverse effect on our business, consolidated financial condition or results of operations.

Competitive Pressures from Electric Industry Deregulation Could Adversely Affect Our Revenues and Reported Earnings

Neither the Kansas Legislature nor the KCC has taken action in the recent past to establish retail competition in our service territory. We currently apply the accounting principles of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), to our regulated business and at December 31, 2003 had recorded $397.0 million of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either as a result of the establishment of retail competition in Kansas or an expectation that permitted rates would not allow us to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets.

We Face Financial Risks From Our Nuclear Facility

Risks of substantial liability arise from the ownership and operation of nuclear facilities, including, among others, structural problems at a nuclear facility, the storage, handling and disposal of radioactive materials, limitations on the amounts and types of insurance coverages commercially available and uncertainties with respect to the technological aspects of nuclear decommissioning at the end of their useful lives and anticipated increases in the cost of nuclear decommissioning and costs or measures associated with public safety. In the event of an extended or unscheduled outage at Wolf Creek, we would be required to purchase power in the open market to replace the power normally produced at Wolf Creek and we would have less power available for sale by us in the wholesale markets. Such purchases would subject us to the risk of increased energy prices and, depending on the length of the outage and the level of market prices, could adversely affect our cash flow. If we were not permitted by the KCC to recover these costs, such events could have an adverse impact on our consolidated financial condition.

We May Face Liability In Ongoing Lawsuits and Investigations

We and certain of our former and present directors and officers are defendants in civil litigation alleging violations of the securities laws. In addition, we continue to cooperate in investigations by a federal grand jury, the SEC and the United States Department of Justice into events at our company during the years prior to 2003. Our former president, chief executive officer and chairman and our former executive vice president and chief strategic officer have asserted significant claims against us in connection with the termination of their employment and the publication of the report of the special committee of our board. Finally, the FERC is investigating certain activities regarding our energy trading activities and our compliance with the FERC standards of conduct. An adverse result in any of these matters could result in damages, fines or penalties in amounts that could be material and adversely affect our consolidated results and financial condition.

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EXECUTIVE OFFICERS OF THE COMPANY

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ITEM 2. PROPERTIES

ELECTRIC UTILITY FACILITIES

We own approximately 6,100 miles of transmission lines, approximately 25,200 miles of overhead distribution lines and approximately 3,200 miles of underground distribution lines.

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

ITEM 3. LEGAL PROCEEDINGS

Information on our legal proceedings is set forth in Notes 3, 17, 19, 20, 21 and 23 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies — EPA New Source Review,” “Legal Proceedings,” “Ongoing Investigations,” “Special Committee Investigation,” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2003.

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PART II

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

STOCK TRADING

Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 23, 2004, there were 31,721 common shareholders of record. For information regarding quarterly common stock price ranges for 2003 and 2002, see Note 30 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

DIVIDENDS

Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for each series, and we must meet our obligations with respect to mandatorily redeemable preferred securities issued by an affiliated trust.

Quarterly dividends on common stock and preferred stock are normally paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, regulation, including the KCC’s order requiring us to reduce our outstanding debt, competition and financial loan covenants. On February 9, 2004, our board of directors declared a first-quarter 2004 dividend of $0.19 per share. We established our dividend at this level in the first quarter of 2003.

On March 4, 2004, our board of directors announced its current intention to begin restoring our dividend to a level consistent with comparable regulated electric utilities following achievement of the Debt Reduction Plan. Subject to a review of our financial results and dividend policy at the time, the board currently anticipates that it will increase the quarterly dividends payable in January 2005.

Our Articles of Incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. We provide further information on these restrictions in Note 22 of the Notes to Consolidated Financial Statements, “Common and Preferred Stock.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock.

For additional information on dividends, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Future Cash Requirements,” Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation” and Note 22, “Common and Preferred Stock,” included herein.

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ITEM 6. SELECTED FINANCIAL DATA

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

INTRODUCTION

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas and at wholesale in a multi-state region in the central United States under the regulation of the KCC and the FERC.

Our goals are to improve our core utility business by improving customer service, continuing to expand our wholesale sales, continuing to reduce debt, improving credit quality and improving our relationships with regulators, shareholders, employees and other interested parties.

Our focus during 2003 was the reduction of debt, primarily through the disposition of non-utility and non-core operations. In 2003, we reduced our debt by $965.7 million primarily through use of the proceeds from the sale of our ONEOK stock and through the retirement of $135.0 million of debt that was economically defeased in 2002. With the closing of the sale of our interest in Protection One on February 17, 2004, we received proceeds of $122.2 million, which will also be used to reduce debt. We plan to issue $100 million to $250 million of equity during 2004.

Key factors affecting our business in any given period include the weather, the economic well-being of our Kansas service territory, performance of our electric generating facilities, conditions in fuel markets and the markets for wholesale electricity and the cost of dealing with public policy initiatives.

As discussed in Note 32 to the Notes to Consolidated Financial Statements, “Restatement of Cash Flow Statements,” the consolidated statements of cash flows for the years ended December 31, 2003, 2002 and 2001 have been restated to correct misstatements in the classification of cash distributions received from investments in foreign power projects, the reinvestment of dividends payable on shares of our common stock issued or reissued under our Direct Stock Purchase Plan and other individually insignificant items. Amounts affected by this restatement included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” have been appropriately revised.

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

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial conditions and results of operations are based on our consolidated financial statements, which have been prepared in conformity with GAAP. Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or susceptibility of matters to change.

Pension Benefit Plans

In accounting for our retirement plans and other post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension benefit plans, which include our portion of WCNOC’s costs, are impacted by management estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs and employee demographics (including age, compensation levels and employment periods). A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the period, or on the amount of related liabilities reflected on our consolidated balance sheets or may also require cash contributions.

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

Revenue Recognition - Energy Sales

Revenues from energy sales are recognized upon delivery to the customer and include an estimate for energy delivered but unbilled at the end of each year. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale during the year measured against total billed sales and our estimates, based on historical data, of the portion of the unbilled revenues attributable to each of our different rate classes (retail or wholesale). If actual sales differ from the estimate, our revenues could be affected. At December 31, 2003, we had estimated unbilled revenue of $42.7 million.

Energy marketing activities are accounted for under the mark-to-market method of accounting. Under this method, changes in the portfolio value are recognized as gains or losses in the period of change. The net mark-to-market change is included in energy sales on our consolidated statements of income (loss). The resulting unrealized gains and losses are recorded as energy trading assets and liabilities on our consolidated balance sheets. We use quoted market prices to value our energy marketing and derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. The quoted market prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

The tables below show fair value of energy trading contracts outstanding for the year ended December 31, 2003, their sources and maturity periods:

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The sources of the fair values of the financial instruments related to these contracts are summarized in the following table:

OPERATING RESULTS

Westar Energy Consolidated

We are pursuing a strategy to return to our core business of providing electric service. We have discussed our 2003 significant accomplishments elsewhere throughout this document. As described in further detail in the “—Segments of Business” discussion that follows, our operating results for 2003 improved based on a variety of factors.

2003 compared to 2002:

Income from operations improved 35% from $274.3 million in 2002 to $371.4 million in 2003. Improved electric sales revenues and the significant decline in selling, general and administrative expense more than offset increased fuel and purchased power expense. Administrative expenses in 2002 were significantly higher due to expenses related to work force reductions and other costs described below. Other income increased by $59.4 million in 2003 because the gain on the sale of our ONEOK stock in 2003 more than offset other declines in investment earnings, losses associated with the settlement of the call option related to our putable/callable notes and losses on the extinguishment of debt. Interest expense declined primarily due to the reduction in our outstanding debt balance. The 2003 results of discontinued operations were significantly improved as compared to 2002. Results in 2002 were adversely impacted by large impairment charges, which are described below. The net effect of these improvements in our consolidated financial position was net income of $85.0 million in 2003 compared to a net loss of $793.0 million in 2002.

2002 compared to 2001:

Income from operations improved 30% from $211.0 million in 2001 to $274.3 million in 2002. Improved electric sales revenues and declines in purchased power and depreciation expenses more than offset increases in administrative expenses related to special committee and grand jury investigation costs, work force reductions and amounts recorded for potential liabilities to Mr. Wittig and Mr. Lake. Additionally, results of discontinued operations more than offset the improvement in our income from operations. In 2002, we recorded impairment charges of $623.7 million, net of $72.3 million tax, associated with goodwill and customer account assets of our monitored services businesses. These large impairment charges are reflected in the results of our discontinued operations and are the primary reason for our net loss of $793.4 million in 2002.

Segments of Business

We evaluate segment performance based on earnings per share and have two reportable segments: “Electric Utility” and “Other.” We have no single customer from which we receive 10% or more of our revenues.

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Electric Utility

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

2003 compared to 2002: Changes in results of operations for the “Electric Utility” segment are as follows:

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The following table reflects changes in electric sales volumes, as measured by thousands of MWh of electricity, for the two years ended December 31, 2003 and 2002. No sales volumes are shown for network integration or energy marketing because these activities are unrelated to electricity we generate.