UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 20052006

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$1,834,449,044 at June 30, 2005.2006.

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:

TABLE OF CONTENTS

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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:concerning matters such as, but not limited to:

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

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These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety. No one section of 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 660,000669,000 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

OverviewNew Generation and Transmission Construction Plans

Retail Rate Review

December 28, 2005 KCC OrderRates

In accordance with a 2003 KCC order,Order, on May 2, 2005, we filed applications with the KCC on May 2, 2005for it to review our retail electric rates. We requestedOn December 28, 2005, the KCC issued an increaseorder (2005 KCC Order) authorizing changes in our retail electric rates, which we began billing in the first quarter of 2006, and approved various other changes to our rate structures. In April 2006, interveners filed appeals with the adoptionKansas Court 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 averageAppeals challenging various aspects of the margins we realize from our market-based wholesale sales. Other significant changes approved2005 KCC Order. On July 7, 2006, the Kansas Court of Appeals reversed and remanded for further consideration by the KCC arethree elements of the RECA,2005 KCC Order. The balance of the 2005 KCC Order was upheld.

On February 8, 2007, the KCC issued an environmental cost recovery rider (ECRR),order in response to the separationKansas Court of Appeals’ decision regarding the 2005 KCC Order. In its February 8, 2007 Order the KCC: (i) confirmed its original decision regarding its treatment of the La Cygne unit 2 sale-leaseback transaction; (ii) in lieu of a 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 costscharge, ruled that have been incurred and deferred as regulatory assets.

Retail Energy Cost Adjustment: The RECA allowsit intends to permit us to recover our transmission related costs in a manner similar to how we recover our other costs; and (iii) reversed itself with regard to the actual costinclusion in depreciation rates of fuel consumed in producing electricity anda component for terminal net salvage. The February 8, 2007 KCC Order requires us to refund to our customers 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.amount we have collected related to terminal net salvage. 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 specifiedrecorded a regulatory liability at December 31, 2006 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$16.4 million related to serve our customers, we attempt to seek out wholesale sales of energy at prices in excessthis item. For additional information, see Note 3 of the costs of production. We are likelyNotes 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 operatingConsolidated Financial Statements, “Rate Matters 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.Regulation.”

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.

OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 355,000360,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 305,000309,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 4845 cities in Kansas and four electric cooperatives that serve rural areas ofin Kansas. We have other 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 allowIn 2006, we implemented a retail energy cost adjustment (RECA) that allows us to recover the actual cost of fuel consumed in producinggenerating electricity and the cost of purchased power effective withneeded to serve our customers. Through the implementationRECA, we bill our customers on a month ahead estimate. The RECA then provides for an annual review and reconciliation of the new rates in February 2006. This applies to all fuel types we useestimated and to our purchased power. The KCC will review ouractual fuel and purchased power purchasing practices on ancosts. The annual basisreview also affords the KCC a means to ensure that these expenses were incurred prudently. If it were determined that any portiondetermine the prudence of our fuel and purchased power expenses. If the KCC determines any expenses were incurred imprudently, these costs could be disallowed by the KCC.are imprudent, it will likely disallow recovery of those costs.

Generation Capacity

We have 5,851 megawatts (MW)6,033 MW of accredited generating capacity, of which 2,6042,587 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.

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Our aggregate 20052006 peak system net load of 4,5494,914 MW occurred on July 25, 2005.19, 2006. Our net generating capacity, combined with firm capacity purchases and sales, provided a capacity margin of approximately 20%11% above system peak responsibility at the time of our 20052006 peak system net load.

We have agreed toUnder wholesale agreements, we provide generating capacity to other utilitiesentities 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 less fuel it takes to produce electricity. TheWe measure the quantity of heat consumed during the generation of electricity is measured in millions of Btu (MMBtu).

Based on MMBtus, our 2005 actual2006 fuel mix was 79% coal, 14%16% nuclear and 7%5% natural gas, oil and diesel fuel. We expect a similarthat our fuel mix in 2006.2007 will have a higher percentage of uranium usage because we do not have a scheduled outage at Wolf Creek in 2007. 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 2,2102,190 MW, of which we own an 84% share, or 1,8571,839 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 isfor those quantities over the scheduled forannual minimum will occur in 2008.

We transport coal from Wyoming under a long-term rail transportation contract with theThe Burlington Northern Santa Fe (BNSF) and Union Pacific railroads.railroads transport coal for Jeffrey Energy Center from Wyoming under a long-term rail transportation contract. 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 20052006 was approximately $1.32$1.37 per MMBtu, or $22.01$23.29 per ton.

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La Cygne Generating Station: The two coal-fired units at La Cygne Generating Station (La Cygne) have an aggregate generating capacity of 1,3981,422 MW, of which we own or lease a 50% share, or 699711 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 2005,2006, the average delivered cost of all coal burned at La Cygne unit 1 was approximately $1.05$1.10 per MMBtu, or $17.91$19.06 per ton. The average delivered cost of coal burned at La Cygne unit 2 was approximately $0.88$0.92 per MMBtu, or $14.76$15.58 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 743774 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 infor 2008 and 2009.

We transportBNSF transports coal for these energy centers 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.2008.

During 2005,2006, the average delivered cost of all coal burned in the Lawrence units was approximately $1.09$1.15 per MMBtu, or $19.22$20.32 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.13$1.15 per MMBtu, or $20.03$20.38 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.facility and the Spring Creek Energy Center. We can 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 2005,2006, we purchased 7.914.7 million MMBtu of natural gas on the spot market for a total cost of $67.2$95.7 million. Natural gas accounted for approximately 3%5% of our total MMBtu of fuel burned during 20052006 and approximately 16%24% 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, 2006.2007. 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. We meet all of the natural gas transportation requirements for the Spring Creek Energy Center through an interruptible natural gas transportation agreement with ONEOK Gas Transportation, LLC.

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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 20052006 oil was moderately more economicalexpensive than natural gas, therefore,and because of the additional handling cost of oil and additional environmental considerations associated with oil, we useddid not use oil as the primary fuel in these generating facilities for most of 2005.in 2006. During 2005,2006, we burned 11.5only 0.3 million MMBtu of oil at a total cost of $57.3$2.3 million. Oil accounted for approximately 4%less than 1% of our total MMBtu of fuel burned during 20052006 and approximately 13%1% 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 isWe also used as a start-up fuel atuse oil to start some of our coal 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.

Other Fuel Matters

The table below provides theour weighted average cost of fuel, that we have used, including transportation costs.

Purchased Power

At times, we purchase power to meet the energy needselectricity instead of our customers.generating it ourselves. Factors that cause us to purchase power to serve our customersmake such purchases include planned and unscheduled 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 keeplimit our ability to bring purchased electricity into our control area, potentially requiring us from purchasing power in which case we would have to implement curtailmentcurtail or interruption proceduresinterrupt our customers as permitted by our tariffs and terms and conditions of service. Purchased power for the year ended December 31, 20052006 comprised approximately 8%7% of our total operating expenses. The weighted average cost of purchased power was $54.90 per MWh in 2006, $59.05 per MWh in 2005 and $54.10 per MWh in 2004 and $52.33 per MWh in 2003.2004.

Energy Marketing Activities

We engage in both financial and physical trading to increasewith the goal of increasing profits, manage ourmanaging commodity price risk and enhanceenhancing 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.

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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 aan equal 47% interest, in Wolf Creek and a 6% interest is owned bywith Kansas Electric Power Cooperative, Inc. (KEPCo). holding the remaining 6% interest. The co-owners pay operating costs equal to their percentage ownership in Wolf Creek.

In September 2006, Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, filed a request with the Nuclear Regulatory Commission (NRC)for a 20 year extension of Wolf Creek’s operating license. Currently, the operating license will expire in 2025. We anticipate that the NRC may take up to two years before it rules on the request. The NRC may impose conditions as part of any approval. Based on the experience of other nuclear plant operators, we believe that the NRC will ultimately approve the request.

Fuel Supply

We have under contract 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 issued2011. During 2006, we entered into contracts with suppliers forwhich will cover a majority of Wolf Creek’s uranium and conversion and enrichment requirements extendingneeds through 2017. Fabrication and enrichment requirements are under contract through 2024.

AllBecause of a supply interruption at a major Canadian uranium mine, Wolf Creek will defer a small portion of the uranium fuel scheduled for delivery in 2007. This supply interruption may impact Wolf Creek’s uranium deliveries in subsequent years as well. In anticipation of this possibility, Wolf Creek’s owners authorized the purchase of additional uranium from an alternate supplier. We expect this purchase, combined with Wolf Creek’s on-going operations strategies including its previous acquisition of strategic inventory, will minimize the impact of this fuel supply interruption. We cannot provide assurance that our mitigation efforts will eliminate the risk that supplies are not delivered as needed.

We have entered into all uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreement, have been entered intoagreements in the ordinary course of business, and webusiness. 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 and flooding of a key mine of a leading industry supplier have introduced uncertainty as to the ability to replace, if necessary, some ofvolumes under these contracts in the event of a protracted supply disruption. We believe this potential problemuncertainty is commonnot unique 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 $4.1 million in 2006, $3.8 million in 2005 and $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 by the DOE 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)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 2025, the expirationterm of its existing operating license in 2025.license.

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Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. Should disposal capability become unavailable, we believe 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 acreating new disposal facility to be developed within one ofcapability for the member states. The Central States Compact Commission selected Nebraska as the host state for the disposal facility.

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 4134 days in 20052006 for its fourteenthfifteenth scheduled refueling and maintenance outage. During outages at the plant, we meetmet our electric demand primarily with our fossil-fueledother generating units and by purchasing power, depending on availability and cost.power. As provided by the KCC, we defer and amortize evenly the incremental maintenance costs incurred for planned refueling outages evenly over the unit’s 18 month operating cycle. Wolf Creek is next scheduled to be taken off-line in the fallspring of 20062008 for its fifteenthsixteenth 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. Those concerns need not be related to Wolf Creek specifically, but could be due to concerns about nuclear power generally, or circumstances at other nuclear plants in which we have no ownership.

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 sufficient 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 revised nuclear decommissioning study, the current-year funding and future funding. Phase two isinvolves the filingreview and approval by the KCC 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.

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In 2005, 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 areis 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 regulations, 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.expires. We believe that the KCC approved funding level will also be sufficient to meet the NRC minimum financial assurance requirement. However, ourOur consolidated results of operations would be materially adversely affected if we are not allowed to recover in utility rates the full amount of the funding requirement.

Nuclear decommissioning costs that areWe recovered in rates areand deposited in an external trust fund. In 2005, we expensedfund approximately $3.9 million for nuclear decommissioning.decommissioning in 2006 and 2005 and $3.8 million in 2004. We record our investment in the nuclear decommissioning fund at fair value. The fair value approximated $111.1 million as of December 31, 2006 and $100.8 million atas of December 31, 2005 and $91.1 million at December 31, 2004.2005.

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 andThe Federal Energy Regulatory Commission (FERC) requires owners of regulated 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 utilitiesassets to allow third partiesparty wholesale providers of electricity nondiscriminatory access 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 provideallow ourselves. In December 1999, FERC issued an order encouraging the formation of regional transmission organizations (RTO)(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.wholesale power markets.

Regional Transmission Organization

We are a member of the Southwest Power Pool (SPP).SPP, the RTO in our region. On October 1, 2004, FERC granted RTO status to the SPP. As a result, if approved bySeptember 19, 2006 the KCC we expectapproved an order allowing us to transfer functional control of our transmission system to the SPP RTO under its membership agreement and applicable tariff. The SPP RTO will coordinatecoordinates the operation of our transmission system within an interconnected transmission system acrossthat covers all or portions of eight states. The SPP will collectcollects revenues attributable tofor the use of each member’stransmission owner’s transmission system. Members and transmissionTransmission customers will be able to transmit throughout the entire SPP system 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 transmissionmarket. Transmission capacity needed to serve its retail customers. Any additional transmission capacity will beis sold on a first come/first served non-discriminatory basis. All transmission customers will beare charged uniform rates for use ofapplicable to the transmission system in the zone where energy is delivered, including entitiestransmission customers 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,operations, although we expect higher costs to increase due to the establishmentadministrative costs 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

The SPP is required by FERC requires RTOs to establishimplement a real-time market to accommodate financial settlement of energy imbalance market.imbalances within the SPP region. An energy imbalance exists when a transmission market participant’s productionactual power inputs to or outputs from the transmission network differ from the level of inputs and consumption of energy in real time does not net to zero.outputs scheduled by the transmission user. The intent of a real-time market system is to permit more efficient balancing of energy production and consumption through the use of energy and to manage congestion in real time.market protocols. The SPP plans to implement aimplemented the real-time energy imbalance market system on MayFebruary 1, 2006.2007. At this time we are not ableunable to identify the fulldetermine what impact this may have on our results of operations.

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Regulation and Rates

As a Kansas electric utility, we are subject to the jurisdiction oflaw gives 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.

FERC Proceedings

Request for Change in Transmission Rates:On May 2, 2005, we filed applications with FERC that proposeproposed a formula transmission rate that providesproviding 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 separately for transmission service. Theseservice through a transmission delivery charge. The proposed FERC transmission rates became effective, onsubject to refund, December 1, 2005. On November 7, 2006 FERC issued an order reflecting a unanimous settlement reached by the parties to the proceeding. The settlement modified the rates we proposed and requires us to refund approximately $3.4 million, which includes the amount we collected in the interim rates since December 2005 subject to refund. We can provide no assuranceand interest on 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.amount.

Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. These laws and regulations relate 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,The 2005 KCC Order established the ECRR,environmental cost recovery rider (ECRR), which will allow for the timely inclusion in rates of capital expenditures that areinvestments we make related 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,sulfur dioxide (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 certainprescribed 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.requirements of this act. 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 thatin the market in which such allowances are anticipated to emit SO2 in an amount less than their allowances.traded. In 2005,2006, we had enough emissions allowances adequate to meet planned generation and we expect to have enough in 2006. The2007. In the future we may need to purchase additional allowances. We expect to recover 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 RuleRule. The rule caps permanently, and seeks to permanently cap and reduce, the amount of mercury emissionsthat may be emitted from coal-fired power plants. The Clean Air Mercury Rule requires reductions of mercury in two phases, the first starting in 2010. To comply with this rule we will need to install and maintain additional controlsequipment at our coal-fired units will be required as well as the installation of additional emission monitoring equipment.units. Several different environmental groups and states are challenging this rule in court, which could potentially delay the implementation of this rule.its implementation. 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 uswe will be the installation, certificationneed to have installed and operation of mercurycertified by January 1, 2009, continuous emissions mercury monitoring systems on each coal-fired unit by January 1, 2009. Based on currently available information, we cannot estimate ourunit. We do not know what the costs to comply with the Clean Air Mercury Rule will be, but these costswe believe they 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.

WeEnvironmental requirements have been changing substantially. Accordingly, we may be required to further reduce emissions of presently regulated gases and substances, such as SO2 , NOx, particulate matter and mercury and we may be required to reduce or limit emissions of gases and substances not presently regulated (e.g., carbon dioxide (CO2) as a result of various other current or pending laws, including,). Proposals and bills in particular:those respects include:

Based on currently available information, we cannot estimate our costs to comply with these proposed laws, but we believe 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 thatcurrently expect our share of these capital costs willthrough the scheduled completion in 2009 to be approximately $105.0$232.5 million. Additionally, we have identified the potential for up to $515.0$512.4 million of capital expenditures for environmental projects at our other power plants for other environmental projects during the next 8seven to ten years. This costOur estimated costs of these projects have increased since we first announced these programs. These amounts could increase further depending on the resolution of the EPA New Source Review described below.below and other factors. In addition to the capital investment, werewhen we to install such equipment, we anticipate that we wouldwill also incur significant annual expense to operate and maintain the equipment and the operation of the equipment would reducereduces net production from our plants. As discussed above, theThe ECRR will allowallows for the timely inclusion in rates of capital expenditures that aretied directly tied to environmental improvements required by the Clean Air Act. However, increased operating and maintenance costs, other than expenses related to production-related consumables, such as limestone, can only be recovered only through a change in our base rates following a rate review.

The degree to which we will need to reduce emissions and the timing of when such emissions controls 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 New Source Review described below. In addition, the availability of equipment and contractors can affect the timing and ultimate cost of equipment installation. We expect to recover such costs through the rates we charge our customers.

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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.Center. 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. We are not able to estimate the possible loss or range of loss at this time.

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.million. 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 allthe purchaser of our former Missouri assets in the Missouri manufactured gas sites. According to the termsamount of the agreement, our liability for these sites is capped at $7.5 million and terminates in 2009.million.

SEASONALITY

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

EMPLOYEES

As of February 28, 2006,15, 2007, we had 2,1912,223 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 1,2811,279 employees as of February 28, 2006.15, 2007.

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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.comwww.westarenergy.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

Executive officers serve at the pleasure of the board of directors. There are no family relationships among any of the executive officers, nor any arrangements or understandings between any executive officer and other persons pursuant to which he was appointed as an executive officer.

ITEM 1A. RISK FACTORS17

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the performanceenergy use of our customers. OurThe value of our common stock price and our 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 retail 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 and a return on 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 base rates virtually unchanged andbut approved various other changes into our rate structure.structure that allow some adjustment to our prices. The KCC also approved the RECA, which is based on the actualallows us to recover cost of fuel for generation and purchased power expense less(less margins earned on wholesale sales, andsales). It also authorized us to implement the ECRR, which is based onallows us to change our rates to reflect the impact of 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

OnceExcept to the extent the KCC permits us to modify our prices by using specific adjustments and riders such as the RECA and the ECRR, 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.review. We may electapply 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 programprograms in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must either produce replacement power from our other, usually less efficient, units or purchase power from others at unpredictable and potentially higher cost in order to supplymeet our customers and perform our contractual agreements.sales obligations. In addition, thisequipment failure can prevent us from having powerlimit our ability to sell in themake opportunistic sales to wholesale market. customers.

Fuel Deliveries Can Be Interrupted or Slowed and Transmission Systems May Be Constrained

Coal deliveries from the PRB region of Wyoming, which is the primary source for our coal, have been slower than expectedcan be interrupted or can be slowed due primarily to problems with the rail tracks usedtraffic congestion, equipment or track failure, or due to deliver our coal and operationalloading problems at the mines where the coal is obtained. If rail delivery cycle times do not improve,mines. This may require that we may be required to continue ourimplement coal conservation efforts andand/or take other compensating measures. We experienced these problems and conserved coal to varying degrees in 2005 and 2006. These measures may 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-basedopportunistic 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, deliverabilityalong with the prices and prices, price volatility of fuel and other commodities and transportation availability and costswholesale electricity 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 tiedin our rates the costs that we incur to comply with environmental improvement through our rates,regulations, we can provide no assurance that we wouldwill be able to fully and timely recover all or any increased operating and maintenance costs relating to environmental compliance.such costs. 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 SFASStatement of Financial Accounting Standard (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business. AtAs of December 31, 2005,2006, we had recorded $275.0 million of regulatory assets, net of regulatory liabilities. At December 31, 2004, we had recorded $334.6$476.0 million of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either asas: (i) a result of the establishment of retail competition in our service territoryterritory; (ii) a change in the regulatory approach for setting rates from cost-based ratemaking to another form of ratemaking; or an expectation(iii) other regulatory actions that permitted rates would not allow usrestrict cost recovery to a level insufficient to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Such an action would materially reduce our shareholders’ equity. We periodically review these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based upon current evaluation of the various factors that are expected to impact future cost recovery, we believe that our regulatory assets are probable of recovery.

We Face Financial Risks From Our Nuclear FacilityAssociated With Wolf Creek

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 efficientmore costly generating 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 ininto the wholesale markets. If we were not permitted by the KCC to recover these costs, such events couldwould likely have an adverse impact on our consolidated financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Coal deliveries from the PRBPowder River Basin 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 fromimproved in 2006; however, they continue to be slower than historical averages due primarily to issues at the PRB region of Wyoming.

coal mines and with the rail delivery system. During 2005 and continuing in 2006, we implemented compensating measures based on delivery cycle times, our assumptions about future delivery cycle times, fuel usage and planned inventory levels. TheseWe may continue to use these measures included,as conditions warrant. The compensating measures include, but wereare not limited to,to: reducing coal consumption during off-peakcertain periods, by revising normal operational dispatch of our generating units, purchasing power or using more expensive power to serve customers, decreasingfrom others, reducing 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 effecteffects of additional purchased power expense and the reduction in sales due to slower coal deliveries hashave been partially offset by higher prices received for the power we have sold in the power markets.market-based wholesale sales prices.

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 their susceptibility of matters to change.

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 customerutility rates. Regulatory liabilities represent probable obligations to makefuture reductions in revenue or refunds to customers for previous collections for costs that are not likely to be incurred in the future.customers.

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 to be probable, we would record a charge against income in the amount of the related regulatory assets would be required to be expensed in current period earnings.assets.

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 PostretirementPost-retirement Benefits Other Than Pensions.Pensions” and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132(R).”

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.

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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 $21.4 million in 2006, $12.2 million in 2005 and $5.1 million in 20042004. These amounts reflect the pension expense of Westar Energy and our 47% responsibility for the pension incomeexpense of approximately $1.0 million in 2003.Wolf Creek. Pension expense for 2006 is expected to approximate $20.4 million, which represents an $8.2 million increase over 2005. The increase isincreases are due 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,rates, lower returnreturns on assets, increaseincreases in salary scalesalaries and updated mortality tables. Pension expense for 2007 is expected to be approximately $20.1 million.

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

Revenue Recognition – Energy Sales

We recognize revenuesrecord revenue as electricity is delivered. Amounts delivered to individual customers are determined through the systematic monthly readings of customer meters. At the end of each month, the electric usage from retailthe last meter reading is estimated and corresponding unbilled revenue is recorded.

The accuracy of the unbilled revenue estimate is affected by factors that include fluctuations in energy sales upon delivery todemands, weather, line losses and changes in the composition of 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, weclasses. We had estimated unbilled revenue of $38.4 million as of December 31, 2006 and $42.1 million.million as of December 31, 2005.

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We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the value of contracts in our portfolio value as gains or losses in the period of change. With the exception of contracts for fuel contracts,that we purchase to produce energy in our power plants, 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 areis 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 valuesvalue 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 the fair value of energy marketing and fuel contracts that were outstanding for the year endedas of December 31, 2005,2006, their sources and maturity periods.

The sources of the fair values of the financial instruments related to these contracts as of December 31, 2006 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.

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We record deferred tax assets for capital loss,losses, operating losslosses and tax credit carryforwards. However, when there arewe believe we do not or will not have 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 we determine, based on the weight of available evidence that it is considered more likely than notunlikely that we will realize some portion or all of the deferred tax asset will not be realized.asset. 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.

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.revenue subject to refund.

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

Market-based wholesale: Sales of energy to other wholesale customers, the raterates for which isare generally based on prevailing market prices as allowed by our FERC approved market-based tariff. Alsotariff, or where not permitted, pricing is based on incremental cost plus a permitted margin. This category also includes changes in valuations of contracts that have yet to settle.

Energy marketing: Includes: (1) market-based energy(i) transactions unrelatedbased on market prices with volumes not related to the production of our generationgenerating assets or the needsdemand of our regulatedretail customers; (2)(ii) financially settled products and physical transactions sourced outside our control area; and (3)(iii) changes in valuations for contracts that have yet to settle that may not be recorded in tariff- or market-based wholesale revenues.

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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 and availability 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 summersHot summer temperatures and very cold winterswinter temperatures prompt more demand, especially among our residential customers. Mild weather reducesserves to reduce customer demand.

2006 Compared to 2005

Below we discuss our operating results for the year ended December 31, 2006 compared to the results for the year ended December 31, 2005. Changes in results of operations are as follows.