View:

Download DOC

Download PDF

Download XLS

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2003

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)

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

Table of Contents

TABLE OF CONTENTS

2

Table of Contents

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:

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.

3

Table of Contents

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” and 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 provide electric generation, transmission and distribution services to approximately 298,000 customers in south-central and southeastern Kansas, including the Wichita metropolitan area. Our corporate headquarters is located in Wichita, Kansas.

We own 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.

SIGNIFICANT BUSINESS DEVELOPMENTS

KCC Orders and The Debt Reduction Plan

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

On July 21, 2003, Westar Energy and 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:

4

Table of Contents

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 $1.7 million for revenue to be refunded, which is included in other liabilities on our consolidated balance sheets.

ELECTRIC UTILITY OPERATIONS

General

We supply 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 25 Kansas cities. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities.

Generation Capacity

We have 2,596 megawatts (MW) of generating capacity, including Wolf Creek. 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 2,145 MW occurred on August 21, 2003. This is also our all-time peak system net load. We do not anticipate needing additional generating capacity through at least 2006.

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

5

Table of Contents

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 62% coal, 31% nuclear and 7% 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, 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 a 20% share, or 443 MW. Westar Energy, the operator of Jeffrey Energy Center, 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 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 $0.7 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 $1.19 per MMBtu, or $19.99 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.

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 $0.87 per MMBtu, or $15.07 per ton. The average delivered cost of coal burned at LaCygne 2 was approximately $0.76 per MMBtu, or $13.17 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 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.

6

Table of Contents

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, Jeffrey Energy Center can be served by only one rail carrier. In the event the rail carrier 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 long-term 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 and Neosho Energy Centers. 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 1.6 million MMBtu of natural gas on the spot market for a total cost of $7.4 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 fuels 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.”

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. The agreement for the Neosho facility extends through June 1, 2016.

Oil

Our Gordon Evans, Murray Gill and Neosho 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 burned 8.3 million MMBtu of oil for a total cost of $26.5 million. Oil accounted for approximately 6% of our total fuel burned during 2003.

Oil is also used as a start-up fuel at some of our generating stations and in our diesel generator. 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

7

Table of Contents

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, 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. We own a 47% interest in Wolf Creek, or 548 MW, which represents 21% 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 35% 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

8

Table of Contents

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.

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.

9

Table of Contents

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.

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

10

Table of Contents

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 could 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 facilities, 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.

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

11

Table of Contents

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.

Westar Energy and 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 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

12

Table of Contents

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 sulfur dioxide (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 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:

13

Table of Contents

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 Westar Energy under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants it operates. On January 22, 2004, the EPA notified Westar Energy that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.

Westar Energy is in discussions with the EPA concerning this matter but is unable to predict whether the EPA will take further enforcement action. Westar Energy 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 Westar Energy is required to pay any fines or penalties or update or install emissions controls at Jeffrey Energy Center 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 Westar Energy is assessed a penalty as a result of the EPA’s allegation, the penalty could be material and may not be recovered in rates. We anticipate that we would be allocated a portion of any of these potential costs.

EMPLOYEES

Westar Energy provides all employees we utilize. As of February 29, 2004, Westar Energy had approximately 2,000 employees. Its current contract with 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 Westar Energy’s website at www.wr.com or by responding to requests addressed to its investor relations department at Investor Relations, Westar Energy, Inc., P.O. Box 889, Topeka, Kansas, 66601-0889; phone number (785) 575-1898. 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 Westar Energy’s website is not part of this document.

14

Table of Contents

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 first priority mortgages pursuant to which bonds have been issued and are outstanding.

15

Table of Contents

ITEM 3. LEGAL PROCEEDINGS

Information on our legal proceedings is set forth in Notes 3, 13, 15 and 16 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies — EPA New Source Review,” “Legal Proceedings,” and “Ongoing Investigations,” 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.

ITEM 6. SELECTED FINANCIAL DATA

16

Table of Contents

INTRODUCTION

We are a rate-regulated electric utility in Kansas and a wholly owned subsidiary of Westar Energy. We provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name “Westar Energy.” 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 business by improving customer service, continuing to expand our wholesale sales, improving credit quality and improving our relationships with regulators, shareholders, employees and other interested parties.

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 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.

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 $22.7 million.

We are allocated our share of revenues from energy marketing activities that are jointly entered into with Westar Energy based on actual fuel burned at our generating facilities. The amount of actual fuel burned by a given generating facility is largely determined by utilizing the most economical units first. 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. 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 trading 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.

17

Table of Contents

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

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

OPERATING RESULTS

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 outside our service territory, the cost of fuel and purchased power, price volatility and available generation capacity.

18

Table of Contents

2003 compared to 2002: Changes in results of operations are as follows:

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 because this activity is unrelated to electricity we generate.

Retail sales revenues declined due primarily to the accrual of approximately $1.7 million to be refunded to customers in 2005 and 2006 pursuant to a KCC order. The remainder of the decline in retail sales revenues was because of the effect of the weather on usage of electricity by residential customers, which caused residential sales volumes to decline. Commercial and industrial sales revenues showed slight decreases while sales volumes remained increased slightly compared to 2002.

The increases in wholesale sales revenues more than offset the decline in retail sales revenues. Higher wholesale market prices were the primary cause of improvement in wholesale sales revenues. The higher wholesale market prices more than offset the decline in wholesale sales volumes.

The primary reason our fuel expense increased is because of the higher cost of natural gas and oil used for generation. While we used less MMBtu of natural gas and oil during 2003 than we did during 2002, we spent $2.2 million more for natural gas and oil during 2003 than we spent during the prior year. During periods of high energy use in 2003, we purchased more power from other sources than we did during the same periods of 2002 because it was more economical to purchase power than to operate our peaking units. Our peaking units are primarily natural gas burning units; the higher price of natural gas was the primary factor in determining whether it was more economical to purchase power or to operate our peaking units.

19

Table of Contents

Selling, general and administrative expenses declined in 2003, due primarily to a reduction in incremental administrative expenses incurred in 2002 that were allocated to us for Westar Energy’s work force reduction. Depreciation and amortization expense decreased due primarily to the adoption of new depreciation rates on April 1, 2002 pursuant to a KCC order. Operating and maintenance expense increased due primarily to increased general maintenance expenses at our generating facilities in 2003. General maintenance expenses increased by $4.8 million, partially offsetting the declines in selling, general and administrative and depreciation expenses.

2002 compared to 2001: Changes in results of operations are as follows:

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 because this activity is unrelated to electricity we generate.

Residential sales revenues increased due primarily to the increase in residential sales volumes. The increase was due primarily to favorable weather conditions but was partially offset by lower retail rates. The lower retail rates are attributable to the rate reductions ordered by the KCC in July 2001.

Commercial sales volumes were similarly affected by favorable weather conditions, however, the lower retail rates had a larger impact on commercial customers, causing the larger reduction in commercial sales revenues. Industrial sales revenues decreased primarily because of weaker economic conditions experienced in our service territory, principally associated with the downturn in the aircraft industry.

20

Table of Contents

Wholesale revenues increased approximately $12.9 million as a result of the increase in wholesale sales volumes. Revenues attributable to the increase in wholesale sales volumes were partially offset by lower market prices. In addition, on January 1, 2001, we adopted SFAS No. 133 that required that we report a $21.4 million gain in 2001 on certain derivative contracts as a cumulative effect of a change in accounting principle rather than include the gain in revenues.

Nuclear fuel expense decreased $4.3 million in 2002 as compared to 2001. Because there was no refueling outage of Wolf Creek during 2001, the plant used more fuel during 2001. The remainder of the decline in fuel expense was due primarily to using more natural gas in 2001 than in 2002 at a higher average fuel price. Purchased power expense increased due primarily to the 2002 Wolf Creek refueling outage.

Selling, general and administrative expenses increased due primarily to employee severance costs related to a work force reduction at Westar Energy that were allocated to us. Operating and maintenance expense increased due primarily to $32.9 million in charges associated with the network integration transmission tariff as discussed in “— Other Information — Network Integration Transmission Service.” General maintenance expense at our generating facilities declined $7.6 million, or 22%, due primarily to the lower forced outage rates at our generating units, which partially offset the increase in transmission expense.

The increases in selling, general and administrative expenses and operating and maintenance expenses were partially offset by a decline in depreciation expense. Depreciation expense declined $11.2 million due primarily to changes in depreciation rates as ordered by the KCC on July 25, 2001 and on April 1, 2002.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Most of our cash requirements consist of capital and maintenance expenditures designed to improve and maintain facilities that provide electric service and meet future customer service requirements. Our ability to provide the cash or debt to fund our capital expenditures depends on many things, including available resources, our financial condition and current market conditions.

We expect our internally generated cash to be 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 problem that could require us to obtain a credit facility for our short-term cash needs and that could result in higher borrowing costs.

Capital Resources

The Debt Reduction Plan provides for a systematic disposal of Westar Energy’s non-utility and non-core assets and the planned issuance of Westar Energy equity securities. The net proceeds of these transactions have been and 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 expects to issue equity securities in 2004 in private transactions, public offerings or both.

Our mortgage prohibits additional first mortgage bonds from being issued (except in connection with certain refundings) unless our net earnings before income taxes and accounting change 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. In addition, the issuance of bonds is subject to limitations based on the amount of bondable property additions. As of December 31, 2003, approximately $889.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

21

Table of Contents

Cash Flows from Operating Activities

Our primary source of operating cash flows is the operations of our electric utility business. Cash flows from operating activities increased $17.2 million to $154.8 million in 2003 from $137.6 million in 2002. This increase was mostly attributable to favorable changes in our working capital requirements, primarily restricted cash and accounts payable, partially offset by an increase in accounts receivable.

Cash Flows used in Investing Activities

In general, cash used for investing purposes relates to the growth and maintenance of our utility operations. Our business is capital intensive and requires significant investment in plant on an annual basis. We spent $106.0 in 2003, $78.3 million in 2002, and $82.8 in 2001 on net additions to property, plant and equipment.

Cash Flows used in Financing Activities

Net cash used in financing activities totaled $29.1 million for the year ended December 31, 2003 as compared to $40.5 million for the same period in 2002. In 2003, cash was used to retire long-term debt and to pay $100.0 million in dividends to Westar Energy. The cash used to retire long-term debt was from funds placed in a trust in 2002. Partially offsetting this decrease was a reduction in net advances from Westar Energy.

Net cash used in financing activities totaled $40.5 million for the year ended December 31, 2002 as compared to $6.1 million for the same period in 2001 due primarily to $135.0 million of funds that were irrevocably deposited with the bond trustee to provide for the repayment of our 7.6% first mortgage bonds that were due December 15, 2003.

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. The Debt Reduction Plan requires us to pay our share of the combined rebates to retail customers totaling $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. Westar Energy and we believe these rebates can be funded with internally generated cash flow and available borrowing capacity under Westar Energy’s revolving credit facility.

If Westar Energy is required to update emissions controls or take other remedial action at Jeffrey Energy Center as a result of the EPA’s investigation of Westar Energy, the costs could be material. Westar Energy may also have to pay fines or penalties or make significant capital or operational expenditures related to the notice of violation Westar Energy received from the EPA in connection with certain projects completed at the Jeffrey Energy Center. In addition, significant capital or operational expenditures may be required in order to comply with future environmental regulations or in connection with future remedial obligations. We anticipate that we would be allocated a portion of any of these potential costs.

Our business requires significant capital investments. Through 2006, we expect we will need cash mostly for ongoing utility construction programs designed to improve facilities providing electric service. Other than making planned upgrades to existing facilities, we do not anticipate needing additional generating capacity through at least 2006. We expect these cash needs to be met with internally generated cash flow and existing Westar Energy revolving credit facility.

22

Table of Contents

Capital expenditures for 2003 and anticipated capital expenditures for 2004 through 2006 are as follows:

These estimates are prepared for planning purposes and will be revised from time to time. Actual expenditures will differ from our estimates. These amounts do not include any estimate of expenditures that may be incurred as a result of the EPA investigation or other enacted or proposed environmental regulations.

Maturities of long-term debt as of December 31, 2003 are as follows:

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 reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, 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, 2003, and represent only those amounts that we were contractually obligated to meet as of December 31, 2003. We may from time to time enter into new contracts to replace contracts that have expired.

The following table summarizes the projected future cash payments for our contractual obligations existing at December 31, 2003:

23

Table of Contents

Debt Covenants

Some of Westar Energy’s debt instruments contain restrictions that require it to maintain various coverage and leverage ratios as defined in the agreements. Westar Energy’s calculations of these ratios are performed in accordance with its debt agreements and are used solely to determine compliance with its various debt covenants. Westar Energy was in compliance with these covenants as of December 31, 2003.

Accounts Receivable Sales Program

On July 28, 2000, Westar Energy and KGE entered into an agreement with WR Receivables Corporation, a wholly owned, bankruptcy-remote special purpose entity (SPE) to sell all of their accounts receivable arising from the sale of electricity to the SPE. These transfers are accounted for as sales in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The SPE then sells up to $125 million of an undivided interest in our combined accounts receivable to a third party conduit under various terms and conditions. The percentage ownership interest in receivables held by the third party conduit will increase or decrease over time, depending on the characteristics of the SPE’s receivables, including delinquency rates and debtor concentrations. The agreement with the third party conduit is renewable annually upon agreement by all parties. On July 23, 2003, the term of the agreement was extended through July 21, 2004.

See Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities,” for additional information regarding our SPE transactions.

Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation Number (FIN) 46, “Consolidation of Variable Interest Entities,” which was subsequently revised in December 2003 with the issuance of FIN 46R. See Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities” for additional information.

Debt Financings

On June 6, 2002, Westar Energy entered into a secured credit agreement providing for a $585.0 million term loan and a $150.0 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 6.875% senior unsecured notes (with an outstanding principal balance of $184.5 million) before June 1, 2004, the secured credit agreement will mature on June 1, 2004. All loans under the credit agreement are secured by our first mortgage bonds. The proceeds of the term loan were used to retire the existing $400.0 million revolving credit facility of Westar Energy with an outstanding principal balance of $380.0 million, to provide for the repayment at maturity of $135.0 million principal amount of our first mortgage bonds that were due December 15, 2003 together with accrued interest, to repurchase approximately $45.0 million of Westar Energy’s outstanding unsecured notes and to pay customary fees and expenses of the transactions.

In February 2004, Westar Energy repaid the remaining balance of $114.1 million under its $585.0 million term loan that was due in 2005 with internally generated cash and a portion of the proceeds received from the sale of its monitored services businesses.

On March 12, 2004, Westar Energy replaced its $150.0 million revolving credit facility discussed above with a new secured credit agreement providing for $300.0 million revolving credit capacity. The new credit agreement matures on March 12, 2007. All loans under the credit agreement are secured by our first mortgage bonds.

24

Table of Contents

Capital Structure

Our consolidated capital structure at December 31, 2003 and 2002 was as follows:

Credit Ratings

Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service (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 when due on our securities.

On December 19, 2003, Moody’s assigned Westar Energy and us a speculative liquidity rating of SGL-3, which reflects its view that Westar Energy has “adequate” liquidity. On January 5, 2004, S&P affirmed its ratings for Westar Energy and us and revised its outlook for us from developing to positive. On March 1, 2004 Fitch raised its ratings for Westar Energy and us and assigned us a stable outlook.

As of March 1, 2004, ratings with these agencies are as follows:

In general, less favorable 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 in Note 4 of the Notes to Consolidated Financial Statements, “Accounts Receivable and Variable Interest Entities.” We may enter into new credit agreements that contain credit conditions, which could affect our liquidity and/or our borrowing costs.

New Accounting Pronouncements

Accounting for Energy Trading Contracts

In May 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends the accounting for derivative instruments, including certain derivative instruments embedded in other contracts for hedging activities, and clarifies which contracts qualify as “normal purchase/normal sale” contracts. SFAS No. 149 also amends certain other existing pronouncements and requires contracts with comparable characteristics to be accounted for similarly. In particular, SFAS No. 149 clarifies when a contract with an initial net investment meets the characteristics of a derivative and when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS No. 149 was effective for contracts entered into or modified after June 30, 2003. Adoption of SFAS No. 149 has not had a material effect on our consolidated results of operations, financial position or cash flows.

25

Table of Contents

In October 2002, the FASB, through the Emerging Issues Task Force (EITF), reached consensus on EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” EITF Issue No. 02-03, in part, rescinded Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, all new contracts entered into after October 25, 2002 can no longer be marked-to-market and recorded in earnings unless they fall within the scope of SFAS No. 133. We were unaffected by this change in accounting principle and were not required to reclassify any of our contracts since our energy trading contracts qualify as derivative instruments under the guidance of SFAS No. 133. EITF Issue No. 02-03 also requires reporting energy trading contracts and derivative contracts in the income statement on a net basis effective January 1, 2003, whether the contracts are settled financially or physically. We began classifying our energy trading contracts on a net basis during the third quarter of 2002 and have reclassified all prior periods to reflect this presentation.

In August 2003, the FASB issued EITF Issue 03-11, “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to the FASB Statement No. 133 and Not “Held For Trading Purposes” as Defined in Issue No. 02-3.” The reporting of realized gains and losses on physically settled derivative contracts based on the economic substance of the transaction. Our physically settled transactions are reported on a gross basis in the income statement in accordance with EITF Issue 03-11 guidance.

Potential Accounting Changes

At its September 9, 2003 meeting, the American Institute of Certified Public Accountants Accounting Standards Executive Committee approved a Statement of Position (SOP), “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment,” subject to the Accounting Standards Executive Committee’s positive clearance of certain revisions and the FASB clearance. The revised draft SOP sent to the FASB for clearance provides guidance on accounting for certain costs and activities relating to property, plant and equipment (PP&E). The following principles apply to the accounting for PP&E costs within the scope of the SOP.

PP&E consists of one or more components, which should be recorded at cost. A PP&E component should be depreciated over its expected useful life. The costs of a replacement component and the component replaced should not concurrently be recorded as assets. The SOP requires that an entity determine the level of component accounting for its PP&E, which should be set no higher than the functional unit level (i.e., a power plant, a building). A component is a tangible part or portion of PP&E that (1) an entity has elected to account for separately as an asset and (2) is expected to provide economic benefit for more than one year. In order for a replacement to be capitalized, the replaced item needs to have been previously separately accounted for as a component. If an entity replaces a part or portion of a separate component that previously has not been accounted for as a separate component, the replacement would be charged to expense. If, however, the entity determines that the replacement will be accounted for as a separate component in the future, this constitutes a change in accounting principle under APB Opinion 20. The method is to be applied consistently from period to period. Indirect, general and administrative costs and occupancy costs should be charged to expense as incurred. Additionally, under provisions of the SOP, major maintenance costs are to be expensed as incurred. Accordingly, we would be required to expense Wolf Creek refueling costs as incurred absent the regulatory treatment afforded these costs by the KCC. Removal costs should be considered costs associated with the removed component rather than any replacement component, and should be charged to expense. The SOP would be effective for fiscal years beginning after December 15, 2004.

OTHER INFORMATION

City of Wichita Franchise

On February 10, 2004, the Wichita city council approved a ten-year renewal of the franchise pursuant to which we provide retail electric service to the City of Wichita. The new ten-year franchise agreement is on terms that we believe to be reasonably similar to those previously in effect.

26

Table of Contents

Network Integration Transmission Service

Effective January 1, 2002, we began taking Network Integration Transmission Service under the SPP’s Open Access Transmission Tariff. 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 functional control over our transmission system, although we still own our transmission assets and maintain responsibility for dispatching electricity, providing reliable transmission service, maintaining our transmission system and restoring our transmission system in the event there is a disruption to our system.

Currently, all revenues collected within an SPP zone for network integration transmission costs are allocated back to the transmission owner serving the zone. In 2003, our transmission costs for the our zone were approximately $32.7 million. This amount, less $2.9 million that was retained by the SPP as administration cost, was returned to us as revenues. In 2002, our transmission costs were approximately $32.9 million with an administration cost of $2.9 million retained by the SPP. The SPP administration cost is recovered as part of retail rates and a charge to the applicable wholesale customers taking network integration transmission service. The revenues received are reflected in electric sales, and the related charges are expensed and included in reported operating expense.

Stranded Costs

Stranded costs for a utility business are commitments or investments in, and carrying costs on, PP&E, contractual obligations 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 may restrict our ability to charge prices needed to recover costs already incurred or 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 are probable of future recovery. If we discontinue SFAS No. 71 accounting treatment based on competitive or other events, 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, 2003, we have recorded regulatory assets currently subject to recovery in future rates of approximately $316.7 million. Of this amount, $155.8 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 asset retirement obligations, loss on reacquired debt, refinancing costs on the LaCygne 2 lease, deferred plant costs and coal contract settlement costs.

In a competitive environment, we may not be able to fully recover our entire investment in Wolf Creek. We presently own 47% of Wolf Creek. We may also have stranded costs related to 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.

Asset Retirement Obligations

In January 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Any income effects are offset by regulatory accounting pursuant to SFAS No. 71.

27

Table of Contents

Legal Liability - Wolf Creek

On January 1, 2003, we recognized 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. 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. The asset retirement obligation is included on our consolidated balance sheets in other long-term liabilities. Costs to retire Wolf Creek are currently being recovered through rates as provided by the KCC.

Non-legal Liability - Cost of Removal

We have recovered amounts in rates to provide for recovery of the probable costs of removing utility plant assets, but which do not represent legal retirement obligations. The amounts recovered were included as a component of depreciation expense in accordance with the FERC and KCC required ratemaking treatment. With the adoption of SFAS No. 143 we were required to quantify the net cost of removal included in accumulated depreciation. At December 31, 2002, we had $7.5 million included in accumulated depreciation that has been reclassified to other assets. At December 31, 2003, we had $2.1 million in removal costs that have been classified as a regulatory asset. The net amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to removal costs incurred. Therefore, if in the future we recover removal costs in excess of amounts incurred we will recognize a regulatory liability for that amount. We do not anticipate that the adoption of SFAS No. 143 will have any impact on our electric rates.

See Note 14 of the Notes to Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information regarding our asset retirement obligations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Hedging Activity

Westar Energy and we jointly use 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, we use hedging arrangements to reduce some of our exposure to increased coal, natural gas and oil prices. Our future exposure to changes in fossil fuel prices will be dependent on 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 — Hedging Activities,” for detailed information regarding hedging relationships.

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 represents the risk of loss associated with movements in market interest rates. In the future, we may use swaps or other financial instruments to manage interest rate risk.

28

Table of Contents

Credit risk represents 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 we 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 consolidated financial results depending on the success of our credit risk management efforts.

Commodity Price Exposure

We are exposed to commodity price changes and use derivative contracts for non-trading purposes and a mix of various fuels 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 energy trades. 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 possible transmission constraints, and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

From 2002 to 2003, we experienced a 34% increase in the average price per MWh of electricity purchased for utility operations. The volatility in the purchased power market could be greater than the average price increase indicates. Additionally, short-term, but extreme price volatility could potentially be of greater significance than the change in the average price would indicate, especially during adverse weather or market conditions. If we were to have a 10% increase in the price of our purchased power from 2003 to 2004, given the amount of power purchased for utility operations during 2003, we would have exposure of approximately $1.5 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices.

We use various fossil fuels, including coal, natural gas and oil, to operate our system. A significant portion of our coal requirements are purchased under long-term contracts. During 2003, we experienced an approximate 31% increase, or $1.07 per MMBtu, in our average cost for natural gas purchased for utility operations. Due to this substantial increase in natural gas cost, we decreased our natural gas usage by 12.3 million MMBtu compared to the amount burned in 2002. Due to the volatility of natural gas prices, we have begun to increasingly utilize our ability to switch to lower cost fuels as the market and our equipment allow, primarily by using oil in our natural gas burning facilities. During 2003, we increased our oil usage by 14.5 million MMBtu compared to the amount burned in 2002. Although the average cost of oil used for utility operations increased $0.68 per MMBtu, or approximately 27%, compared to the average cost in 2002, it was $1.31 per MMBtu cheaper than the average cost of the natural gas we burned.

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of fossil fuel used for generation vary from year to year based on the availability, price and deliverability of a given fuel type as well as planned and scheduled outages at our facilities that use fossil fuels and the nuclear refueling schedule. Our customers’ electricity usage could also vary from year to year based on the weather or other factors.

Interest Rate Exposure

We had approximately $46.4 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2003. A 100 basis point change in each debt series’ benchmark rate, used to set the rate for such series would impact income from operations before income taxes on an annualized basis by approximately $0.5 million.

29

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TABLE OF CONTENTS

SCHEDULES OMITTED

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

I, II, III, IV, and V.

30

Table of Contents

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, 2003 and 2002, and the related consolidated statements of income and comprehensive income, cash flows and shareholder’s equity, for each of the three years in the period ended December 31, 2003. 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 the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 and Note 14 to the financial statements, the Company changed its method of accounting for asset retirement obligations in 2003 and accounting for derivative contracts and hedging activities in 2001.

Deloitte & Touche LLP

Kansas City, Missouri

March 15, 2004

31

Table of Contents

KANSAS GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)