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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2005

OR

For the transition period from              to             

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

(Title of Class)

Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act).    Yes  x    No  ¨

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act). Check one:

Large accelerated filer  x                    Accelerated filer  ¨                    Non-accelerated filer  ¨

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

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $2,081,879,276 at June 30, 2005.

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

ITEM 1. BUSINESS

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 660,000 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. KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, 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.

SIGNIFICANT BUSINESS DEVELOPMENTS DURING 2005

Overview

Retail Rate Review

December 28, 2005 KCC Order

In accordance with a 2003 KCC order, we filed applications with the KCC on May 2, 2005 to review our rates. We requested an increase in our retail electric rates and the adoption of other practices under the KCC’s jurisdiction. While the KCC ordered a net increase in our base rates of $38.8 million annually, the increase is substantially offset by the requirement that we credit to retail customers a rolling three-year average of the margins we realize from our market-based wholesale sales. Other significant changes approved by the KCC are the RECA, an environmental cost recovery rider (ECRR), the separation of transmission delivery charges, an increase in annual depreciation expense, an extended recovery period for costs being recovered for which no return is provided and the recovery of various costs that have been incurred and deferred as regulatory assets.

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Retail Energy Cost Adjustment: The RECA allows us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power. The adjustment is based on the actual cost of fuel and purchased power less margins from market-based wholesale sales. We have contracts with certain large industrial customers, the terms of which do not provide for the separate billing of fuel costs. Fuel costs for these customers will continue to be recovered through the rates specified in each of these contracts. These customers represented approximately 8% of our total retail sales volumes for 2005.

Wholesale Sales Margins: The terms of the RECA require that we include, as a credit to recoverable fuel costs, an amount based on the average of the margins realized from market-based wholesale sales during the immediately prior three-year period. In any period we are unable to realize market-based wholesale sales margins at least equal to the amount of the credit, our financial results would be adversely affected. In the short-term, our generating capacity is fixed while the load requirements of our customers change constantly. When our generating capacity is not needed to serve our customers, we attempt to seek out wholesale sales of energy at prices in excess of the costs of production. We are likely to face the prospect of decreasing margins as the energy demands of our retail customers increase, which may result in crediting to retail customers an amount that would exceed the margins realized in the current period.

Environmental Cost Recovery Rider: The ECRR allows for the timely inclusion in rates, without requiring a full rate review, of the capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act. Prior to collection through rates, the KCC will review any environmental expenditures to be considered for recovery under the ECRR. Any increased operating and maintenance costs that result from updating or adding environmental equipment cannot be recovered through the ECRR. These costs would be addressed in future rate reviews.

Transmission Delivery Charge: The December 28, 2005 KCC Order allows us to separate our transmission costs from our base rates charged to retail customers. This allows us to implement a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs, which provides for adjustment on a more timely basis. These rates were proposed in an application filed with the Federal Energy Regulatory Commission (FERC) on May 2, 2005 and became effective on December 1, 2005, subject to refund upon review and approval by FERC.

Depreciation Rates: The December 28, 2005 KCC Order authorized an annual increase in the recovery of depreciation expense of approximately $27.6 million. The approved change in depreciation rates allows for the inclusion of net salvage costs, which include an estimate for the cost of dismantlement of plant facilities.

Disallowed Plant Costs: In 1985, the KCC disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in rates over the original depreciable life of Wolf Creek, or through 2025, but disallowed any return on these costs. In its December 28, 2005 order, the KCC extended the recovery period to correspond to Wolf Creek’s new estimated depreciable life. KGE recognized a loss of $10.4 million in the fourth quarter of 2005 as a result of the decrease in the present value of amounts to be received due to the extension of the recovery period.

Other Regulatory Assets: The December 28, 2005 KCC Order also approved for recovery approximately $50.3 million of deferred maintenance costs associated with restoring utility service to our customers stemming from damage to our lines and equipment in the ice storms that occurred in 2002 and 2005 and various other expenses that are relatively small in relation to the total regulatory asset balance.

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OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 355,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 305,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 48 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 retail service territory.

As discussed above, the December 28, 2005 KCC Order will allow us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power effective with the implementation of the new rates in February 2006. This applies to all fuel types we use and to our purchased power. The KCC will review our fuel and power purchasing practices on an annual basis to ensure that these expenses were incurred prudently. If it were determined that any portion of our fuel and purchased power expenses were incurred imprudently, these costs could be disallowed by the KCC.

Generation Capacity

We have 5,851 megawatts (MW) of generating capacity, of which 2,604 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 2005 peak system net load of 4,549 MW occurred on July 25, 2005. 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 2005 peak system net load.

We have agreed to provide generating capacity to other utilities as set forth below.

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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 less 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 2005 actual fuel mix was 79% coal, 14% nuclear and 7% natural gas, oil and diesel fuel. We expect a similar fuel mix in 2006. Our fuel mix fluctuates with the operation of Wolf Creek, fluctuations in fuel costs, plant availability, customer demand and the cost and availability of power in the wholesale market.

Coal

Jeffrey Energy Center: The three coal-fired units at Jeffrey Energy Center have an aggregate capacity of 2,210 MW, of which we own an 84% share, or 1,857 MW. We have a long-term coal supply contract with Foundation Coal West to supply coal to Jeffrey Energy Center from surface 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 costs of production. The price for quantities 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.

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 expect increases in the cost of transporting coal due to higher prices for the items subject to contractual escalation.

The average delivered cost of coal burned at Jeffrey Energy Center during 2005 was approximately $1.32 per MMBtu, or $22.01 per ton.

La Cygne Generating Station: The two coal-fired units at La Cygne Generating Station (La Cygne) have an aggregate generating capacity of 1,398 MW, of which we own or lease a 50% share, or 699 MW. La Cygne unit 1 uses a blended fuel mix containing approximately 85% PRB coal and 15% Kansas/Missouri coal. La Cygne unit 2 uses PRB coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne. All of the La Cygne unit 1 and La Cygne unit 2 PRB coal is supplied through fixed price contracts through 2010 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 La Cygne unit 1 Kansas/Missouri coal is purchased from time to time from local Kansas and Missouri producers.

During 2005, the average delivered cost of all coal burned at La Cygne unit 1 was approximately $1.05 per MMBtu, or $17.91 per ton. The average delivered cost of coal burned at La Cygne unit 2 was approximately $0.88 per MMBtu, or $14.76 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 743 MW. During 2005, we began purchasing coal under a contract with Arch Coal, Inc. This contract extends 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 2006 and 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.

We transport coal from Wyoming using the BNSF railroad under a contract that expires in December 2006. We anticipate entering into a similar contract when the current contract expires. We expect increases in the cost of transporting coal due to higher prices.

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During 2005, the average delivered cost of all coal burned in the Lawrence units was approximately $1.09 per MMBtu, or $19.22 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.13 per MMBtu, or $20.03 per ton.

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 Tecumseh Energy Center 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 Energy Centers. We purchase natural gas in the spot market, which supplies our facilities with natural gas to meet our operational needs. During 2005, we purchased 7.9 million MMBtu of natural gas on the spot market for a total cost of $67.2 million. Natural gas accounted for approximately 3% of our total MMBtu of fuel burned during 2005 and approximately 16% of our total fuel expense. From time to time, we may purchase derivative contracts or use other fuel types in an effort to mitigate the effect of high natural gas prices. 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. This contract expires April 30, 2006. We are currently renegotiating this contract. 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 2005 oil was more economical than natural gas, therefore, we used oil as the primary fuel in these generating facilities for most of 2005. During 2005, we burned 11.5 million MMBtu of oil at a total cost of $57.3 million. Oil accounted for approximately 4% of our total MMBtu of fuel burned during 2005 and approximately 13% of our total fuel expense. From time to time, we may purchase derivative contracts or use other fuel types in an effort to mitigate the effect of high oil prices. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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 contract. 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.

Because oil does not burn as cleanly as natural gas, our ability to use as much oil in the future could be constrained by environmental regulations. See “– Environmental Matters” below for additional information.

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Other Fuel Matters

The table below provides the weighted average cost of fuel that we have used, including transportation 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 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. Transmission constraints 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, 2005 comprised approximately 8% of our total operating expenses. The weighted average cost of purchased power was $59.05 per MWh in 2005, $54.10 per MWh in 2004 and $52.33 per MWh in 2003.

Energy Marketing Activities

We engage in both financial and physical trading to increase profits, manage our commodity price risk and enhance system reliability. 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.

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 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. (KEPCo). The co-owners pay operating costs equal to their percentage ownership in Wolf Creek.

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Fuel Supply

We have 100% of the uranium and conversion services needed to operate Wolf Creek through September 2009 under contract. We also have 100% of the enrichment services required to operate Wolf Creek through March 2008 under contract. Letters of intent have been issued with suppliers for a majority of Wolf Creek’s uranium, conversion and enrichment requirements extending through 2017. 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 we believe 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 the ability to replace, if necessary, some of these contracts in the event of a protracted supply disruption. We believe this potential problem is common in the nuclear industry. Accordingly, in the event the affected contracts were required to be replaced, we believe that the industry and government would arrive at a solution to reduce disruption of the nuclear industry’s operations.

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 into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. Our share of the fee was $3.8 million in 2005, $4.3 million in 2004 and $3.8 million in 2003 and is calculated as one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. We include these costs in operating expenses.

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. Currently, the DOE has not defined a schedule for submitting a license application. 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 has on-site temporary storage for spent nuclear fuel expected to be generated by Wolf Creek through the expiration of its operating license in 2025.

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. We believe 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 (Central States Compact), and the Central States Compact Commission, which is responsible for causing a new disposal facility to be developed within one of the member states. The Central States Compact Commission selected Nebraska as the host state for the disposal facility.

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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 and the Central States Compact Commission 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 Central States 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 Central States Compact Commission settled the case. In August 2005, we received $9.2 million in proceeds from the Central States Compact as a result of the settlement.

Outages

Wolf Creek operates on an 18-month refueling and maintenance outage schedule. Wolf Creek was shut down for 41 days in 2005 for its fourteenth scheduled refueling and maintenance outage. 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. Wolf Creek is scheduled to be taken off-line in the fall of 2006 for its fifteenth refueling and maintenance outage.

An extended or unscheduled shutdown of Wolf Creek could cause us to purchase replacement power, rely more heavily on our other generating units and reduce amounts of power available for us to sell at wholesale.

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. 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 expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning and dismantlement study with the KCC every three years.

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 of its pro rata share of the plant.

Wolf Creek filed an updated nuclear decommissioning site study with the KCC. Based on the 2005 site study of decommissioning costs, including the costs of decontamination, dismantling and site restoration, our share of such costs are estimated to be $243.3 million. This amount compares to the 2002 site study estimate for decommissioning costs of $220.0 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

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 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.

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Nuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2005, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. The fair value approximated $100.8 million at December 31, 2005 and $91.1 million at December 31, 2004.

Competition and Deregulation

Electric utilities have historically operated in a rate-regulated environment. FERC, the federal regulatory agency that has 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 (RTO). 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 transfer functional control of our transmission system to the SPP RTO under its membership agreement and applicable tariff. The SPP RTO will coordinate the operation of our transmission system within 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.

Real-Time Energy Imbalance Market

FERC requires RTOs to establish a real-time energy imbalance market. An energy imbalance exists when a transmission market participant’s production and consumption of energy in real time does not net to zero. The intent of a real-time market system is to permit efficient balancing of production and consumption of energy and to manage congestion in real time. The SPP plans to implement a real-time energy imbalance market system on May 1, 2006. At this time, we are not able to identify the full impact on our results of operations.

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, 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.

Retail Rate Review

As discussed above in “– Significant Business Developments During 2005 – Retail Rate Review,” our rates and cost of service were changed by the December 28, 2005 KCC Order.

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FERC Proceedings

Request for Change in Transmission Rates: On May 2, 2005, we filed applications with FERC that propose a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs. This is consistent with our proposals filed with the KCC on May 2, 2005 to separately charge retail customers for transmission service. These rates became effective on December 1, 2005, subject to refund. We can provide no assurance that FERC will ultimately approve our applications as filed.

Market-based Rates: On March 23, 2005, FERC instituted a proceeding concerning the reasonableness of our market-based rates in our electric control area and the electrical control areas of Midwest Energy, Inc. and Aquila, Inc.’s West Plains Energy division. We have provided FERC with information it requested for its analysis. A FERC decision, anticipated in 2006, could affect how we price future wholesale power sales to wholesale customers in our control area and to Midwest Energy and West Plains Energy and wholesale customers in their control areas. We do not expect the outcome of this matter to significantly impact our consolidated results of operations.

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. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations. As discussed above, the December 28, 2005 KCC Order established the ECRR, which will allow for the timely inclusion in rates capital expenditures that are directly tied to environmental improvements required by the Clean Air Act.

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 such increased costs from our customers or that our business, consolidated financial condition or results of operations will not be materially and adversely affected as a result of costs to comply with such existing and future laws and regulations.

Air Emissions

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

Certain Kansas Department of Health and Environment (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.

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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. In 2005, we had enough emissions allowances to meet planned generation and we expect to have enough in 2006. The cost of emission allowances consumed is eligible to be recovered through the RECA. 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 March 15, 2005, the EPA issued the Clean Air Mercury Rule to permanently cap and reduce mercury emissions from coal-fired power plants. The Clean Air Mercury Rule requires reductions of mercury in two phases starting in 2010. To comply with this rule, additional controls at our coal-fired units will be required as well as the installation of additional emission monitoring equipment. Several different environmental groups and states are challenging this rule in court, which could potentially delay the implementation of this rule. To date, no part of the Clean Air Mercury Rule has been stayed by any court although court cases remain open. Assuming this rule is not stayed, the first significant compliance date for us will be the installation, certification and operation of mercury continuous emissions monitoring systems on each coal-fired unit by January 1, 2009. Based on currently available information, we cannot estimate our costs to comply with the Clean Air Mercury Rule, but these costs could be material.

On March 10, 2005, in a separate but related action, the EPA issued the Clean Air Interstate Rule (CAIR) that addresses the impact of interstate transport of air pollutants on downwind states. CAIR requires reductions of SO2 and NOx in certain states in two separate phases, the first in 2010 and the second in 2015. Several states, including Kansas, are not included in the CAIR region, which reduces the impact this rule has on us.

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.

Environmental Projects

KCPL began updating or installing additional equipment related to emissions controls at La Cygne unit 1 for which we incurred costs beginning in 2005. We will continue to incur costs through the completion of installation in 2009. We anticipate that our share of these costs will be approximately $105.0 million. Additionally, we have identified the potential for up to $515.0 million of expenditures at other power plants for other environmental projects during the next 8 years. This cost could increase depending on the resolution of the EPA New Source Review described below. In addition to the capital investment, were we to install such equipment, we anticipate that we would incur significant annual expense to operate and maintain the equipment and the operation of the equipment would reduce net production from our plants. As discussed above, the ECRR will allow for the timely inclusion in rates capital expenditures that are directly tied to environmental improvements required by the Clean Air Act. However, increased operating and maintenance costs can only be recovered through a change in our base rates following a rate review.

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EPA New Source Review

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

We are in discussions with the EPA concerning this matter in an attempt to reach a settlement. We expect that any settlement with the EPA could require us to update or install emissions controls at Jeffrey Energy Center over an agreed upon number of years. Additionally, we might be required to update or install emissions controls at our other coal-fired plants, pay fines or penalties, or take other remedial action. Together, these costs could be material. The EPA has informed us that it has referred this matter to the Department of Justice (DOJ) for the DOJ to consider whether to pursue an enforcement action in federal district court. We believe that costs related to updating or installing emissions controls would qualify for recovery through the ECRR. If we were to reach a settlement with the EPA, we may be assessed a penalty. The penalty could be material and may not be recovered in rates.

Manufactured Gas Sites

We have been associated with a number of former manufactured gas sites located in Kansas and Missouri. We and the KDHE entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the sites, our liability for twelve of the sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three sites.

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

SEASONALITY

As a summer peaking utility, our sales are seasonal. The third quarter typically accounts for our highest sales volumes. The volume of sales is affected by weather conditions, the economy of our service territory and the performance of our customers.

EMPLOYEES

As of February 28, 2006, we had 2,191 employees. Our current contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers extends through June 30, 2008. The contract covered 1,281 employees as of February 28, 2006.

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ACCESS TO COMPANY INFORMATION

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

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EXECUTIVE OFFICERS OF THE COMPANY

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ITEM 1A. RISK FACTORS

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

Our Revenues Depend Upon Rates Determined by the KCC

The KCC regulates many aspects of our business and operations, including the retail rates that we charge customers for electric service. Retail rates are set by the KCC using a cost-of-service approach that takes into account historical operating expenses, fixed obligations and recovery of capital investments. Using this approach, the KCC sets rates at a level calculated to recover such costs and a permitted return on investment. Other parties to a rate review or the KCC staff may contend that our rates are excessive. Effective January 2006, the KCC authorized changes in our rates that left our rates virtually unchanged and approved various other changes in our rate structure. The KCC also approved the RECA, which is based on the actual cost of fuel and purchased power expense less margins earned on wholesale sales, and the ECRR, which is based on capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act.

Our Costs May Not be Fully Recovered in Retail Rates

Once established by the KCC, our rates generally remain fixed until changed in a subsequent rate review, except to the extent the KCC permits us to modify our tariffs using interim adjustment clauses, such as the RECA and the ECRR. We may elect to file a rate review to request a change in our rates or intervening parties may request that the KCC review our rates for possible adjustment, subject to any limitations that may have been ordered by the KCC.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity requires the use of expensive and complicated equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must either produce replacement power from our less efficient units or purchase power from others at unpredictable and potentially higher cost in order to supply our customers and perform our contractual agreements. In addition, this can prevent us from having power to sell in the wholesale market. Coal deliveries from the PRB region of Wyoming, which is the primary source for our coal, have been slower than expected due primarily to problems with the rail tracks used to deliver our coal and operational problems at the mines where the coal is obtained. If rail delivery cycle times do not improve, we may be required to continue our coal conservation efforts and take other compensating measures. These measures include, but are not limited to, reducing coal consumption by revising normal dispatch of generation units, purchasing power or using more expensive power to serve customers and decreasing or, if necessary, eliminating market-based wholesale sales. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. These factors, as well as weather, interest rates, economic conditions, fuel availability, deliverability and prices, price volatility of fuel and other commodities and transportation availability and costs are largely beyond our control. Costs that are not recovered through the RECA could have a material adverse effect on our consolidated earnings, cash flows and financial position. We engage in energy marketing transactions to reduce risk from market fluctuations, enhance system reliability and increase profits. The events mentioned above could reduce our ability to participate in energy marketing opportunities, which could reduce our profits.

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

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements under the Clean Air Act. This notification was delivered as part of an investigation by the EPA regarding maintenance activities that have been conducted since 1980 at Jeffrey Energy Center. The EPA has informed us that it has referred this matter to the DOJ for it to consider whether to pursue an enforcement action in federal district court. The remedy for a violation could include fines and penalties and an order to install new emission control systems at Jeffrey Energy Center and at certain of our other coal-fired power plants, the associated cost of which could be material.

Our activities are subject to environmental regulation by federal, state, and local governmental authorities. These regulations generally involve the use of water, discharges of effluents into the water, emissions into the air, the handling, storage and use of hazardous substances, and waste handling, remediation and disposal, among others. Congress or the State of Kansas may enact legislation and the EPA or the State of Kansas may propose new regulations or change existing regulations that could require us to reduce certain emissions at our plants. Such action could require us to install costly equipment, increase our operating expense and reduce production from our plants.

The degree to which we will need to reduce emissions and the timing of when such emissions control equipment may be required is uncertain. Both the timing and the nature of required investments depend on specific outcomes that result from interpretation of regulations, new regulations, legislation, and the resolution of the EPA investigation described above. Although we expect to recover capital expenditures directly tied to environmental improvement through our rates, we can provide no assurance that we would be able to fully and timely recover all or any increased operating and maintenance costs relating to environmental compliance. Failure to recover these associated costs could have a material adverse effect on our consolidated financial condition or results of operations.

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

We currently apply the accounting principles of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business. At December 31, 2005, we had recorded $275.0 million of regulatory assets, net of regulatory liabilities. At December 31, 2004, we had recorded $334.6 million of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either as a result of the establishment of retail competition in our service territory or an expectation that permitted rates would not allow us to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets.

We Face Financial Risks From Our Nuclear Facility

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

We own approximately 6,100 miles of transmission lines, approximately 23,600 miles of overhead distribution lines and approximately 3,500 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.

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ITEM 3. LEGAL PROCEEDINGS

On September 21, 2004, a grand jury in Travis County, Texas, indicted us on charges that a $25,000 contribution by us in May 2002 to a Texas political action committee violated Texas election laws. We believe the indictment is without merit and we intend to vigorously defend against the charges. If convicted, the court could impose a fine of up to $20,000 or, in certain circumstances, in an amount not to exceed twice the amount caused to be lost by the commission of the felony. As a result of the indictment, the federal government could suspend our status as a government contractor. Upon a conviction, the federal government could bar us from acting as a government contractor. We are taking action to ensure that neither of these events occur, but we do not know whether we will be successful. We are unable to predict the ultimate impact either suspension or loss of our status as a government contractor would have on our consolidated financial position, results of operations and cash flows.

Information on other legal proceedings is set forth in Notes 3, 14, 16, 17 and 18 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies – EPA New Source Review,” “Legal Proceedings,” “Ongoing Investigations” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

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

No matter was submitted to a vote of our security holders through the solicitation of proxies or otherwise during the fourth quarter of 2005.

PART II

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

STOCK TRADING

Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 28, 2006, there were 27,604 common shareholders of record. For information regarding quarterly common stock price ranges for 2005 and 2004, see Note 24 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

DIVIDENDS

Holders of our common stock are entitled to dividends when and as declared by our board of directors. However, prior to the payment of common dividends, we must first pay dividends to the holders of preferred stock based on the fixed dividend rate for each series.

Quarterly dividends on common stock and preferred stock have historically been paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Our board of directors reviews our common stock dividend policy from time to time. Among the factors the board of directors considers in determining our dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. On February 22, 2006, our board of directors declared a quarterly dividend of $0.25 per share on our common stock payable to shareholders on April 3, 2006. The indicated annual dividend rate is $1.00 per share. We expect to maintain the dividend at this level during 2006.

Our articles of incorporation restrict the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless we meet certain capitalization ratios and other conditions. We provide further information on these restrictions in Note 20 of the Notes to Consolidated Financial Statements, “Common and Preferred Stock.” We do not expect these restrictions to have an impact on our ability to pay dividends on our common stock.

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ITEM 6. SELECTED FINANCIAL DATA

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

INTRODUCTION

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

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2005, and our operating results for the years ended December 31, 2005, 2004 and 2003. As you read Management’s Discussion and Analysis, please refer to our consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Overview

Several significant items have impacted us and our business operations since January 1, 2005.

Retail Rate Review

December 28, 2005 KCC Order

In accordance with a 2003 KCC order, we filed applications with the KCC on May 2, 2005 to review our rates. We requested an increase in our retail electric rates and the adoption of other practices under the KCC’s jurisdiction. While the KCC ordered a net increase in our base rates of $38.8 million annually, the increase is substantially offset by the requirement that we credit to retail customers a rolling three-year average of the margins we realize from our market-based wholesale sales. Other significant changes approved by the KCC are the RECA, the ECRR, the separation of transmission delivery charges, an increase in annual depreciation expense, an extended recovery period for costs being recovered for which no return is provided and the recovery of various costs that have been incurred and deferred as regulatory assets.

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Retail Energy Cost Adjustment: The RECA allows us to recover the actual cost of fuel consumed in producing electricity and the cost of purchased power. The adjustment is based on the actual cost of fuel and purchased power less margins from market-based wholesale sales. We have contracts with certain large industrial customers, the terms of which do not provide for the separate billing of fuel costs. Fuel costs for these customers will continue to be recovered through the rates specified in each of these contracts. These customers represented approximately 8% of our total retail sales volumes for 2005.

Wholesale Sales Margins: The terms of the RECA require that we include, as a credit to recoverable fuel costs, an amount based on the average of the margins realized from market-based wholesale sales during the immediately prior three-year period. In any period we are unable to realize market-based wholesale sales margins at least equal to the amount of the credit, our financial results would be adversely affected. In the short-term, our generating capacity is fixed while the load requirements of our customers change constantly. When our generating capacity is not needed to serve our customers, we attempt to seek out wholesale sales of energy at prices in excess of the costs of production. We are likely to face the prospect of decreasing margins as the energy demands of our retail customers increase, which may result in crediting to retail customers an amount that would exceed the margins realized in the current period.

Environmental Cost Recovery Rider: The ECRR allows for the timely inclusion in rates, without requiring a full rate review, of the capital expenditures made to upgrade our equipment to meet stricter environmental standards required by the Clean Air Act. Prior to collection through rates, the KCC will review any environmental expenditures to be considered for recovery under the ECRR. Any increased operating and maintenance costs that result from updating or adding environmental equipment cannot be recovered through the ECRR. These costs would be addressed in future rate reviews.

Transmission Delivery Charge: The December 28, 2005 KCC Order allows us to separate our transmission costs from our base rates charged to retail customers. This allows us to implement a formula transmission rate that provides for annual adjustments to reflect changes in our transmission costs, which provides for adjustment on a more timely basis. These rates were proposed in an application filed with FERC on May 2, 2005 and became effective on December 1, 2005, subject to refund upon review and approval by FERC.

Depreciation Rates: The December 28, 2005 KCC Order authorized an annual increase in the recovery of depreciation expense of approximately $27.6 million. The approved change in depreciation rates allows for the inclusion of net salvage costs, which include an estimate for the cost of dismantlement of plant facilities.

Disallowed Plant Costs: In 1985, the KCC disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in rates over the original depreciable life of Wolf Creek, or through 2025, but disallowed any return on these costs. In its December 28, 2005 order, the KCC extended the recovery period to correspond to Wolf Creek’s new estimated depreciable life. KGE recognized a loss of $10.4 million in the fourth quarter of 2005 as a result of the decrease in the present value of amounts to be received due to the extension of the recovery period.

Other Regulatory Assets: The December 28, 2005 KCC Order also approved for recovery approximately $50.3 million of deferred maintenance costs associated with restoring utility service to our customers stemming from damage to our lines and equipment in the ice storms that occurred in 2002 and 2005 and various other expenses that are relatively small in relation to the total regulatory asset balance.

Increasing Cost of Fuel and Purchased Power

The cost of power is impacted by, among other factors, customer demand, cost and availability of fuel and purchased power, price volatility, available generation capacity and operating constraints. Higher fuel and purchased power costs, unit outages, and operating constraints, such as our efforts to conserve coal, increased our total fuel and purchased power costs.

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Cost of Fuel and Purchased Power: The cost of fossil fuel has increased since 2004. This is especially true for the cost of natural gas and oil. This higher cost of fuel affects not only the cost of fuel we burn, but also increases the market prices for both our wholesale sales and purchases of power. The cost and availability of fuel may cause us to use higher priced fuel types or to purchase power to meet our customers’ energy needs. The effects of the fuel price increases are reflected in our operating results.

Fuel Supply Contracts: We have a net gain position on our coal supply contract for our Lawrence and Tecumseh Energy Centers. The gain position results primarily from an increase in the price of coal from the PRB region of Wyoming. Based on the terms of this contract, changes in the fair value of this contract are marked-to-market in accordance with the requirements of SFAS No. 133. As a result of the December 28, 2005 KCC Order implementing the RECA, we reversed previously recognized adjustments to fuel expense of $117.7 million related to mark-to-market adjustments and established a regulatory liability. Going forward, we will recognize changes in the fair value of fuel supply contracts as regulatory assets or liabilities.

Unit Availability: Our operating results are significantly influenced by the availability of our generating units. If our more economical units are not available, we must rely on more expensive sources of power to meet our load requirements. The primary outages during the year ended December 31, 2005 were the scheduled refueling and maintenance outage and an unplanned outage at Wolf Creek and planned and unplanned outages at Jeffrey Energy Center and La Cygne. The primary outages during the year ended December 31, 2004 were the planned and unplanned outages and reduced availability of Jeffrey Energy Center.

Operating Constraints: Our operating results are influenced by operating constraints on our generating units, such as coal conservation and maintenance outages. If our more economical units are constrained, we must rely on more expensive sources of power to meet our load requirements and/or forego opportunities in the wholesale power market. During the year ended December 31, 2005, coal conservation efforts, at times, reduced the energy generated at our more economical units and contributed to the decline in our market-based wholesale sales volumes. Coal conservation was required as a result of slower than expected coal deliveries, as discussed below.

Coal Inventory and Delivery: Coal deliveries from the PRB region of Wyoming were slower than expected due primarily to problems with the rail tracks used to deliver our coal and operational problems at the mines where the coal is obtained. Nearly all of the coal used in our coal-fired generating stations is from the PRB region of Wyoming.

During 2005, we implemented compensating measures based on delivery cycle times, our assumptions about future delivery cycle times, fuel usage and planned inventory levels. These measures included, but were not limited to, reducing coal consumption during off-peak periods by revising normal operational dispatch of our generating units, purchasing power or using more expensive power to serve customers, decreasing wholesale sales, transferring rail cars between or among our power plants and purchasing and leasing additional rail cars. These actions helped to reduce the financial impact resulting from longer delivery cycle times. The effect of the reduction in sales due to slower coal deliveries has been partially offset by higher prices received for the power we have sold in the power markets.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with generally accepted accounting principles (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.

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Regulatory Accounting

We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with SFAS No. 71. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent probable obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future.

The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific orders from the KCC, regulatory precedent and the current regulatory environment. To the extent recovery of costs is no longer deemed probable, related regulatory assets would be required to be expensed in current period earnings.

Pension and Post-retirement Benefit Plans Actuarial Assumptions

We and Wolf Creek calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

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

The following table shows the annual impact of a 0.5% change in our pension plan discount rate, salary scale and rate of return on plan assets.

We recorded pension expense of approximately $12.2 million in 2005, $5.1 million in 2004 and pension income of approximately $1.0 million in 2003. Pension expense for 2006 is expected to approximate $20.4 million, which represents an $8.2 million increase over 2005. The increase is primarily due to the amortization of investment losses from prior years that are recognized on a rolling four-year average basis and changes in assumptions including a lower discount rate, lower return on assets, increase in salary scale and updated mortality tables.

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The following table shows the annual impact of a 0.5% change in our post-retirement benefit plan discount rate and rate of return on plan assets.

Revenue Recognition – Energy Sales

We recognize revenues from retail energy sales upon delivery to the customer and include an estimate for energy delivered but unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured against billed sales. At December 31, 2005, we had estimated unbilled revenue of $42.1 million.

We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. With the exception of fuel contracts, we include the net mark-to-market change in sales on our consolidated statements of income. We record the resulting unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. Prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

The tables below show fair value of energy marketing contracts outstanding for the year ended December 31, 2005, their sources and maturity periods.

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

Income Taxes

We use the asset and liability method of accounting for income taxes as required by SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties.

We record deferred tax assets for capital loss, operating loss and tax credit carryforwards. However, when there are not sufficient sources of future capital gain income or taxable income to realize the benefit of the capital loss, operating loss or tax credit carryforwards, we reduce the deferred tax assets by a valuation allowance. We recognize a valuation allowance if, based on the weight of available evidence, it is considered more likely than not that some portion or all of the deferred tax asset will not be realized. We report the effect of a change in the valuation allowance in the current period tax expense.

Asset Retirement Obligations

We calculate our asset retirement obligations and related costs using the guidance provided by SFAS No. 143, “Accounting for Asset Retirement Obligations” and the Financial Accounting Standards Board’s (FASB) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47).

We estimate our asset retirement obligations based on the fair value of the asset retirement obligation we incurred at the time the related long-lived asset was either acquired, placed in service or when regulations establishing the obligation become effective.

In determining our asset retirement obligations, we make assumptions regarding probable disposal costs. A change in these assumptions could have a significant impact on our asset retirement obligations reflected on our consolidated balance sheets.

Contingencies and Litigation

We are currently involved in certain legal proceedings and have estimated the probable cost for the resolution of these claims. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement strategies. It is possible that our future results could be materially affected by changes in our assumptions. See Note 16 of the Notes to Consolidated Financial Statements, “Legal Proceedings,” for more detailed information.

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OPERATING RESULTS

We evaluate operating results based on basic earnings per share. We have various classifications of sales, defined as follows:

Retail: Sales of energy made to residential, commercial and industrial customers.

Other retail: Sales of energy for lighting public streets and highways, net of revenues reserved for rebates.

Tariff-based wholesale: Sales of energy to electric cooperatives, municipalities and other electric utilities, the rate for which is generally based on cost as prescribed by FERC tariffs. Also includes changes in valuations of contracts that have yet to settle.

Market-based wholesale: Sales of energy to other wholesale customers, the rate for which is based on prevailing market prices as allowed by our FERC approved market-based tariff. Also includes changes in valuations of contracts that have yet to settle.

Energy marketing: Includes: (1) market-based energy transactions unrelated to our generation or the needs of our regulated customers; (2) financially settled products and physical transactions sourced outside our control area; and (3) changes in valuations for contracts that have yet to settle that may not be recorded in tariff- or market-based wholesale revenues.

Transmission: Reflects transmission revenues received, including those based on a tariff with the SPP.

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others.

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, among other factors, demand, cost of fuel and purchased power, price volatility, available generation capacity and transmission availability. Changing weather affects the amount of electricity our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand.

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2005 Compared to 2004

Below we discuss our operating results for the year ended December 31, 2005 as compared to the results for the year ended December 31, 2004. Changes in results of operations are as follows.

The following table reflects changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity, for the years ended December 31, 2005 and 2004. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to electricity we generate.

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Residential and commercial sales and sales volumes increased due primarily to warmer weather during 2005 than experienced in 2004. When measured by cooling degree days, the weather during 2005 was 27% warmer than during 2004 and 6% above the 20-year average. We measure cooling degree days at weather stations we believe to be generally reflective of conditions in our service territory.

The warmer weather also contributed to the increased tariff-based wholesale sales and sales volumes. Additionally, about $2.7 million, or approximately 2%, of the increase in the tariff-based wholesale sales was due to the Wolf Creek outages. We sold more tariff-based wholesale power to KEPCo in accordance with a contract to supply replacement power when Wolf Creek is not available. We had more energy available from Jeffrey Energy Center, which also contributed to the increased tariff-based wholesale sales.

Higher prevailing fuel prices have caused wholesale market prices to increase, which was the primary reason our market-based wholesale sales increased. Market-based wholesale sales volumes declined because less energy was available for sale due to the increase in retail and tariff-based wholesale sales.

The change in energy marketing was due primarily to having more favorable changes in market valuations in 2005 compared to 2004 and due to favorable settlements of energy contracts in 2005.

Fuel expense increased due primarily to using more expensive sources of generation because of the lower unit availability of our more economical generating units as discussed above in “– Summary of Significant Items – Increasing Cost of Fuel and Purchased Power – Unit Availability.”

Purchased power expense increased due primarily to a 35% increase in volumes purchased during 2005 as compared to 2004. This was due to the various outages or reduced operating capability at some of our generating units and the availability of economically priced power. At times, it was more economical to purchase power than to operate our available generating units. Also contributing to the increase in purchased power expense was a 9% higher average cost.

Operating and maintenance expense increased due to a number of factors, the largest of which was a $10.4 million write-off of disallowed plant costs as discussed above in “– Summary of Significant Items – Retail Rate Review – December 28, 2005 KCC Order – Disallowed Plant Costs.”

In addition, costs of operating and maintaining our distribution system increased $8.4 million due primarily to higher labor costs and additional maintenance projects. Also causing the operating and maintenance expense to increase was higher taxes other than income tax of $4.7 million, a $3.5 million charge to write off plant operating system development costs at Wolf Creek due to non-performance of the vendor developing the system and higher maintenance costs at our generating units of $2.8 million due to the outages as discussed above in “– Unit Availability.” These higher expenses were partially offset by a $5.4 million decline in expense related to changes in the La Cygne unit 2 operating lease as discussed in Note 21 of the Notes to Consolidated Financial Statements, “Leases.”

Depreciation expense decreased primarily because we established a regulatory asset for the depreciation differences between those used for financial statement purposes and regulatory rate making purposes from August 2001 to March 2002 pursuant to the December 28, 2005 KCC Order, which allowed us to record a reduction in depreciation expense of $20.1 million.

Selling, general and administrative expenses decreased due primarily to reduced legal fees and insurance costs. Partially offsetting these decreases were increased employee pension and benefit costs.

During 2004, we recognized a loss of $16.1 million in connection with the redemption of some of our senior unsecured notes and a loss of $2.7 million in connection with the redemption of the Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A.

Other income during 2005 was higher due primarily to $7.2 million of income from corporate-owned life insurance, which was partially offset by higher interest expense associated with borrowings on corporate-owned life insurance.

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Interest expense decreased during 2005 due to lower debt balances and lower interest rates due to the refinancing activities as discussed in detail in “– Liquidity and Capital Resources” below.

The increase in income tax expense reflects the increase in income from continuing operations before income taxes.

2004 Compared to 2003

Below we discuss our operating results for the year ended December 31, 2004 as compared to the results for the year ended December 31, 2003. Changes in results of operations are as follows.