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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

OR

For the transition period from                      to                     

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

(Title of Class)

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

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

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

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $1,706,425,434 at June 30, 2004.

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

DOCUMENTS INCORPORATED BY REFERENCE:

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” 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 this 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

GENERAL

We are 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., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 653,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita, Kansas. 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.

SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2004

Common Stock Issuance

Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million.

Reduction of Debt

During 2004, we reduced our total debt balance by $533.4 million, from $2.2 billion at December 31, 2003 to $1.7 billion at December 31, 2004.

Discontinued Operations — Sale of Protection One

On February 17, 2004, we closed the sale of our interest in Protection One, Inc. (Protection One) to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). On November 12, 2004, we settled issues remaining after the sale by entering into a settlement agreement with Protection One and Quadrangle that, among other things, terminated a tax sharing agreement, settled Protection One’s claims with us related to the tax sharing agreement and settled claims between Quadrangle and us related to the sale transaction. Our net cash payment under the settlement agreement was $13.4 million. We recorded after tax income from discontinued operations of $78.8 million in 2004 and after tax loss from discontinued operations of $77.9 million in 2003.

OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 352,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 301,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 54 cities in Kansas and four electric cooperatives that serve rural areas of Kansas. We have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we engage in energy marketing and purchase and sell wholesale electricity in areas outside our historical retail service territory.

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Generation Capacity

We have 5,844 megawatts (MW) of generating capacity, of which 2,587 MW is owned or leased by KGE. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.

Our aggregate 2004 peak system net load of 4,455 MW occurred on August 3, 2004. Our net generating capacity combined with firm capacity purchases and sales provided a capacity margin of approximately 20% above system peak responsibility at the time of our 2004 peak system net load.

We have agreed to provide generating capacity to other utilities 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 2004 actual fuel mix was 79% coal, 16% nuclear and 5% natural gas, oil or diesel fuel. We expect in 2005 to use a higher percentage of coal and a lower percentage of uranium because in 2005 we will refuel 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 Foundation Coal West to supply coal to Jeffrey Energy Center from mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu delivery quantities. All of the coal used at Jeffrey Energy Center is purchased under this contract. The contract expires December 31, 2020. The contract provides for price escalation, based on certain indexed costs of production. The price for quantities

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purchased over the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects then current market prices. The next re-pricing is scheduled for 2008.

The coal supplied to Jeffrey Energy Center during 2004 was surface mined and had an average Btu content of approximately 8,449 Btu per pound and an average sulfur content of 0.47 lbs/MMBtu (see “— Environmental Matters” for a discussion of sulfur content). The average delivered cost of coal burned at Jeffrey Energy Center during 2004 was approximately $1.24 per MMBtu, or $20.93 per ton.

We transport coal from Wyoming under a long-term rail transportation contract with the Burlington Northern Santa Fe (BNSF) and Union Pacific railroads. The contract term continues through December 31, 2013. The contract price is subject to price escalation based on certain costs incurred by the rail carriers. We anticipate that the cost of transporting coal may increase due to higher prices for the items subject to contractual escalation.

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 or lease 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), arranges coal purchases and transportation services for LaCygne. 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. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market. 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 2004 had an average Btu content of approximately 8,630 Btu per pound and an average sulfur content of 0.32 lbs/MMBtu. During 2004, the average delivered cost of all coal burned at LaCygne 1 was approximately $0.89 per MMBtu, or $15.51 per ton. The average delivered cost of coal burned at LaCygne 2 was approximately $0.81 per MMBtu, or $13.74 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 752 MW. During 2004, we purchased coal under a contract with Kennecott Coal Sales Company that expired in December 2004. During the first quarter of 2004, we entered into an agreement with Arch Coal, Inc. for coal to be supplied to these energy centers beginning in 2005 and extending through 2009. This contract is expected to provide 100% of the coal requirement for these energy centers through 2007 and 70% of the coal requirements during 2008 and 2009. Approximately 30% of the coal to be delivered under this contract is priced within a specified range of spot market prices for 2005 through 2007 and approximately 43% of the coal to be delivered under this contract is priced within a specified range of spot market prices in 2008 and 2009.

In 2004, the coal supplied to Lawrence and Tecumseh Energy Centers had an average Btu content of approximately 8,905 Btu per pound and an average sulfur content of 0.36 lbs/MMBtu. During 2004, the average delivered cost of all coal burned in the Lawrence units was approximately $1.05 per MMBtu, or $18.58 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.05 per MMBtu, or $18.65 per ton.

We transport coal from Wyoming using the BNSF railroad under a contract ending in December 2006. We anticipate entering into a similar contract when the current contract expires. We anticipate that the cost of transporting coal may increase due to higher prices for the items subject to contractual escalation.

General: We have entered into all of our coal supply agreements in the ordinary course of business and believe we are not 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 we meet the majority of our coal needs through long-term contracts as discussed above, we do not anticipate being materially impacted by price changes in the 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

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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 that could have a material adverse impact on our business, consolidated financial condition and results of operations.

Natural Gas

We use natural gas either as a primary fuel or as a start-up and/or secondary fuel, depending on market prices, at 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. We also use natural gas as a supplemental fuel in the coal-fired units at the Lawrence and Tecumseh generating stations. We purchase natural gas in the spot market, which supplies our facilities with a flexible natural gas supply as necessary to meet operational needs. During 2004, we purchased 4.2 million MMBtu of natural gas on the spot market for a total cost of $28.1 million. Natural gas accounted for approximately 1% of our total fuel burned during 2004.

If natural gas prices are higher than the amount we are able to recover through our retail rates, we may be exposed to increased natural gas costs and our exposure could be material. We may be able to reduce our exposure to the risk of high natural gas prices 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 file a request for a change in rates with the Kansas Corporation Commission (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 maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. (ONEOK). This contract expires April 30, 2006. We expect to renew or renegotiate a new contract to provide this natural gas transportation prior to the current contract expiration. We meet a portion of our natural gas transportation requirements for the Gordon Evans, Murray Gill, Neosho, Lawrence and Tecumseh Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Pipeline. We meet all of the natural gas transportation requirements for the State Line facility 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

Once started with natural gas, most of the steam units at our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn oil or natural gas. We use oil as an alternate fuel when economical or when interruptions to natural gas supply make it necessary. During 2004 oil was more economical than natural gas, therefore, we used oil as the primary fuel in these generating facilities for most of 2004. During 2004, we burned 10.3 million MMBtu of oil at a total cost of $38.9 million. Oil accounted for approximately 4% of our total MMBtu of fuel burned during 2004. Because oil does not burn as cleanly as natural gas, our ability to use as much oil in the future could be constrained by new environmental rules or future settlements regarding environmental matters.

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 our diesel generators. We purchase oil in the spot market and under longer-term contracts. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power, to satisfy emergency requirements and to protect against reduced availability of natural gas for limited periods or when the primary fuel becomes uneconomical to burn.

If oil prices are higher than the amount we are able to recover through our retail rates, we may be exposed to increased oil costs and our exposure could be material. We may be able to reduce our exposure to the risk of high oil prices 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 oil costs in excess of the cost included in retail rates, we would have to file a request for a change in rates 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.”

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Other Fuel Matters

The table below provides information relating to the weighted average cost of fuel that we have used, including the fuel and transportation costs and any other associated costs.

Purchased Power

At times, we purchase power to meet the energy needs of our customers. Factors that cause us to purchase power to serve our customers include outages at our generating plants, prices for wholesale energy, extreme weather conditions, growth, and other factors. If we were unable to generate an adequate supply of electricity to serve our customers, we would typically purchase power in the wholesale market. Constraints in the transmission system may keep us from purchasing power in which case we would have to implement curtailment or interruption procedures as permitted by our tariffs and terms and conditions of service. Purchased power for the year ended December 31, 2004 comprised approximately 6% of our total operating expenses.

Energy Marketing Activities

We engage in both financial and physical trading to manage our energy price risks. We trade electricity, coal, natural gas and oil. We use a variety of financial instruments, including forward contracts, options and swaps and we trade energy commodity contracts daily. We also use economic hedging techniques to manage fuel expenditures.

Nuclear Generation

General

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 approximately 9% of our total generating capacity. KCPL owns a 47% interest in Wolf Creek and a 6% interest is owned by Kansas Electric Power Cooperative, Inc. 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.

Fuel Supply

We have 100% of the uranium and conversion services needed to operate Wolf Creek under contract through September 2009. We also have 100% of the enrichment services required to operate Wolf Creek under contract through approximately March 2008. Fabrication requirements are under contract through 2024. We will be exposed to the price risk associated with any components not currently under contract if a counterparty were to fail its contractual obligations.

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 WCNOC believes Wolf Creek is not substantially dependent on these agreements. However, contraction and consolidation among suppliers of these commodities and services, coupled with increasing worldwide demand and past inventory draw-downs, have introduced uncertainty as to WCNOC’s ability to replace, if necessary, some of these contracts in the event of a protracted supply disruption. WCNOC believes this potential problem is common in the nuclear industry.

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Accordingly, in the event the affected contracts were required to be replaced, WCNOC believes that the industry and government would arrive at a solution to minimize disruption of the nuclear industry’s operations.

Nuclear fuel is amortized to fuel and purchased power 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. We include these disposal costs in operating expenses.

A permanent disposal site will not be available for the nuclear industry until 2012 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 2018. 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 2002, the Yucca Mountain site in Nevada was approved 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 2012. However, the opening of the Yucca Mountain site has been delayed many times and could be delayed further 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. WCNOC believes that a temporary loss of low-level radioactive waste disposal capability would not affect Wolf Creek’s continued operation.

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. Most of the utilities that had provided the project’s pre-construction financing, including WCNOC as well as the Compact Commission itself, filed a lawsuit in federal court contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the court entered a judgment of $151.4 million, 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. Following unsuccessful appeals of the decision by Nebraska, in August 2004 Nebraska and the Compact Commission settled the case. The settlement requires Nebraska to pay the Compact Commission a one-time amount of $140.5 million or, alternatively, four annual installments of $38.5 million beginning in August 2005. The parties agreed to dismiss all pending litigation and appeals relating to this matter. Once Nebraska makes its final payment, it will be relieved of its responsibility to host a disposal facility. Meanwhile, the Compact Commission is pursuing other strategies for providing disposal capability for waste generators in the Compact region.

Outages

Wolf Creek operates on an 18-month refueling and maintenance outage schedule that permits operations during every third calendar year without a refueling outage. Wolf Creek was shut down for 45 days in 2003 for its thirteenth scheduled refueling and maintenance outage, which began on October 18, 2003 and ended on December 2, 2003.

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During outages at the plant we meet our electric demand primarily with our fossil-fueled generating units and by purchasing power depending on availability and cost. As provided by the KCC, we amortize the incremental maintenance costs incurred for planned refueling outages evenly over the unit’s 18 month operating cycle. We do not defer and amortize the incremental fuel or purchased power costs incurred as a result of a refueling outage. Wolf Creek is scheduled to be taken off-line in the spring of 2005 for its fourteenth 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 available to sell at wholesale. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or other concerns.

The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on their safety significance. Wolf Creek currently meets all NRC oversight objectives and receives the minimum regimen of NRC inspections. However, because of Wolf Creek’s recent experience with unscheduled outages, one additional unscheduled outage before September 30, 2005 may result in the NRC lowering the Wolf Creek rating for one performance indicator. This might require additional NRC inspections to evaluate possible corrective actions that if required might result in additional expense or disruption in Wolf Creek’s operation.

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 expense nuclear decommissioning costs over the expected life of Wolf Creek. The amount we expense is based on an estimate of nuclear decommissioning costs that we will incur upon retirement of the plant. Nuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2004, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. Fair value approximated $91.1 million at December 31, 2004 and $80.1 million at December 31, 2003.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the nuclear decommissioning study, the current-year funding and future 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.

We filed an updated nuclear decommissioning and dismantlement cost estimate 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. We expect to file an updated decommissioning cost study with the KCC by September 1, 2005.

We charge nuclear decommissioning costs 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, which, as determined by the KCC for purposes of the funding schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear decommissioning

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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.

Competition and Deregulation

Electric utilities have historically operated in a rate-regulated environment. 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 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 FERC to order electric utilities to allow third parties to use their transmission systems to transport electric power to wholesale customers. In 1992, we agreed to permit third parties access to our transmission system for wholesale transactions. FERC also requires us to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order encouraging the 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.

Regional Transmission Organization

We are a member of the Southwest Power Pool (SPP). On October 1, 2004, FERC granted RTO status to the SPP. As a result, if approved by the KCC, we expect to turn operational control of our transmission system over to the SPP RTO under its membership agreement and applicable tariff. The SPP RTO will operate our transmission system as part of an interconnected transmission system across eight states. The SPP will collect revenues attributable to the use of each member’s transmission system. Members and transmission customers will be able to transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. We believe each transmission owner generally retains the transmission capacity needed to serve its 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 will have a material effect on our operations; however, we expect costs to increase due to the establishment of the RTO and associated markets. At this time, we are unable to quantify these costs because market implementation issues remain unresolved. We expect that we will recover these costs in rates we charge to our customers.

Regulation and Rates

As a Kansas electric utility, we are subject to the jurisdiction of the KCC, which has general regulatory authority over our rates, extensions and abandonments of service and facilities, valuation of property, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale sales of electricity, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety.

As a result of an earlier KCC order, we will file a request for a rate review with the KCC by May 2, 2005, based on a test year consisting of the 12 months ended December 31, 2004.

Effective January 4, 2004, 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 were revised. This legislation was designed to reduce accidents related to driver fatigue. Electric utilities were exempt from implementing these changes until September 2004. During restoration of electric service after a power outage, we must obtain a declaration of a state of emergency in order to gain an exception from these rules. Such an exception permits employees required to restore electric power to operate equipment for extended hours without the otherwise 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 contractors or lengthen electric service outages.

On January 16, 2004, the KCC issued an order regarding electric service reliability for retail customers. The order was intended to help the KCC assess the reliability of retail electric service. Specifically, the KCC wanted

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to establish uniform definitions and requirements regarding service obligations, record keeping, customer notification and methods of reporting results to the KCC. On February 10, 2004, the North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from the investigation of the August 14, 2003 blackout in portions of the northeastern United States. These initiatives will impact our operations in a number of ways, including system relay protection, vegetation management and operator training. The 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. We are unable to estimate potential compliance costs at this time; however, it is likely that our annual capital and maintenance expenditure requirements will increase in the future.

Public Utility Holding Company Act of 1935

Westar Energy is a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) as a result of Westar Energy’s ownership of KGE and Westar Generating, Inc., each a wholly-owned subsidiary. Currently, Westar Energy claims an exemption from registration under the 1935 Act based on its operations being conducted “predominantly” within Kansas. Following a recent decision by the Securities and Exchange Commission (SEC) with respect to its interpretation of the criteria that must be satisfied to claim a “predominantly” intrastate exemption and as a result of the amount of sales of wholesale electricity outside of Kansas by Westar Energy’s energy marketing operations, it is possible that the SEC could question Westar Energy’s eligibility for an exemption from registration under the 1935 Act. In that event, we would evaluate our options, including filing an application for exemption and asking the SEC to formally consider that request, becoming a registered holding company, restructuring our operations in a manner that would allow us to maintain eligibility to claim an exemption or restructuring our organizational structure to consolidate all utility operations into one entity so that Westar Energy is no longer a utility holding company.

In the event we elect to register Westar Energy as a holding company, the 1935 Act and related regulations issued by the SEC would govern its activities and the activities of its subsidiaries with respect to the acquisition, issuance and sale of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters. We are unable to predict whether Westar Energy will continue to be eligible for an exemption for registration under the 1935 Act, however, we believe that Westar Energy becoming a registered holding company under the 1935 Act or taking steps to reorganize our corporate structure to avoid registration would not have a material impact on our consolidated financial position, results of operations or cash flows.

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 the 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).

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Certain Kansas Department of Health and Environment (KDHE) 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 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 operators of affected units that are anticipated to emit SO2 in excess of their allowances may purchase allowances from operators of 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, we had enough emissions allowances to meet planned generation and we expect to have enough in 2005. In future years, we expect to purchase SO2 allowances in order to meet the acid rain requirements of the Clean Air Act. We cannot estimate the cost at this time, but anticipate these costs may be material. The pricing of emissions allowances is unpredictable and may change over time.

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 Clean Air Interstate 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 achievable 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 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 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