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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2006

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 $1,834,449,044 at June 30, 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 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

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 669,000 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

New Generation and Transmission Construction Plans

We plan significant increases in investments in new generation, new transmission and air emission controls at existing fossil-fueled power plants. These investments include new projects and higher investment estimates for previously announced projects, which have increased due to rising prices of labor, materials and supplies.

In August 2006, we announced plans to build a new natural gas-fired combustion turbine peaking power plant near Emporia in Lyon County, Kansas. We expect the new plant, which we have named the Emporia Energy Center, to have an initial generating capacity of up to 300 megawatts (MW), with additional capacity to be added in a second phase, bringing the total capacity to approximately 600 MW. We expect the total investment in the plant to be about $318 million. We plan to begin construction on the new plant in the spring of 2007. The initial phase of the plant is scheduled to begin operation in the summer of 2008.

In September 2006, we announced plans to build a transmission line from our Gordon Evans Energy Center northwest of Wichita, Kansas, to a new substation near Hutchison, Kansas, then onto our Summit substation near Salina, Kansas, a distance totaling approximately 86 miles. In January 2007, we filed an application with the Kansas Corporation Commission (KCC) to request permission to build the line. Kansas law requires the KCC to issue an order within 120 days of our filing regarding our application. If the KCC issues a permit for us to proceed, we expect to complete construction in 2009. Our preliminary cost estimate for the project is $80 million to $100 million. This estimate could change materially as engineering and construction proceed. In addition to this line, we plan additional expansions to our electric transmission network in Kansas. These include a new line from our Rose Hill substation near Wichita to the Kansas-Oklahoma border, where we expect to interconnect with new facilities built by an Oklahoma-based utility, and a new line from our Jeffrey Energy Center to an existing substation about 15 miles south of Topeka, Kansas.

In May 2005, we initiated a study to identify potential sites suitable for a new coal-fired power plant. We said that we intended to ultimately select and announce the preferred site for a base load coal plant by the end of 2006. Due primarily to the significant increase in the estimated costs of constructing such a facility, in December 2006, we announced that we would delay making such a decision. We continue to evaluate how we will meet our future base load capacity needs.

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During 2005 and 2006 we announced plans to make significant investments in our coal plants to reduce air emissions from these plants. The estimated costs of those investments have increased since those earlier announcements. For additional information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Future Cash Requirements.”

Changes in Rates

In accordance with a 2003 KCC Order, on May 2, 2005, we filed applications with the KCC for it to review our retail electric rates. On December 28, 2005, the KCC issued an order (2005 KCC Order) authorizing changes in our 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 Kansas Court of Appeals challenging various aspects of the 2005 KCC Order. On July 7, 2006, the Kansas Court of Appeals reversed and remanded for further consideration by the KCC three elements of the 2005 KCC Order. The balance of the 2005 KCC Order was upheld.

On February 8, 2007, the KCC issued an order in response to the Kansas 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 charge, ruled that it 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 inclusion in depreciation rates of a component for terminal net salvage. The February 8, 2007 KCC Order requires us to refund to our customers the amount we have collected related to terminal net salvage. We have recorded a regulatory liability at December 31, 2006 in the amount of $16.4 million related to this item. For additional information, see Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.”

OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 360,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 309,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 45 cities in Kansas and four electric cooperatives in 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.

In 2006, we implemented a retail energy cost adjustment (RECA) that allows us to recover the cost of fuel consumed in generating electricity and purchased power needed to serve our customers. Through the RECA, we bill our customers on a month ahead estimate. The RECA then provides for an annual review and reconciliation of estimated and actual fuel and purchased power costs. The annual review also affords the KCC a means to determine the prudence of our fuel and purchased power expenses. If the KCC determines any expenses are imprudent, it will likely disallow recovery of those costs.

Generation Capacity

We have 6,033 MW of accredited generating capacity, of which 2,587 MW is owned or leased by KGE. See “Item 2. Properties” for additional information on our generating units. The capacity by fuel type is summarized below.

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Our aggregate 2006 peak system net load of 4,914 MW occurred on July 19, 2006. Our net generating capacity, combined with firm capacity purchases and sales, provided a capacity margin of 11% above system peak responsibility at the time of our 2006 peak system net load.

Under wholesale agreements, we provide generating capacity to other entities 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. We measure the quantity of heat consumed during the generation of electricity in millions of Btu (MMBtu).

Based on MMBtus, our 2006 fuel mix was 79% coal, 16% nuclear and 5% natural gas, oil and diesel fuel. We expect that our fuel mix in 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 2,190 MW, of which we own an 84% share, or 1,839 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 for those quantities over the scheduled annual minimum will occur in 2008.

The Burlington Northern Santa Fe (BNSF) and Union Pacific 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 2006 was approximately $1.37 per MMBtu, or $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 1,422 MW, of which we own or lease a 50% share, or 711 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 2006, the average delivered cost of all coal burned at La Cygne unit 1 was approximately $1.10 per MMBtu, or $19.06 per ton. The average delivered cost of coal burned at La Cygne unit 2 was approximately $0.92 per MMBtu, or $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 774 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 for 2008 and 2009.

BNSF transports coal for these energy centers from Wyoming under a contract that expires in December 2008.

During 2006, the average delivered cost of all coal burned in the Lawrence units was approximately $1.15 per MMBtu, or $20.32 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.15 per MMBtu, or $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 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. During 2006, we purchased 14.7 million MMBtu of natural gas on the spot market for a total cost of $95.7 million. Natural gas accounted for approximately 5% of our total MMBtu of fuel burned during 2006 and approximately 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, 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 2006 oil was moderately more expensive than natural gas, and because of the additional handling cost of oil and additional environmental considerations associated with oil, we did not use oil as the primary fuel in these generating facilities in 2006. During 2006, we burned only 0.3 million MMBtu of oil at a total cost of $2.3 million. Oil accounted for less than 1% of our total MMBtu of fuel burned during 2006 and approximately 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.”

We also use 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 our weighted average cost of fuel, including transportation costs.

Purchased Power

At times, we purchase electricity instead of generating it ourselves. Factors that cause us to make such purchases include planned and unscheduled outages at our generating plants, prices for wholesale energy, extreme weather conditions and other factors. Transmission constraints may limit our ability to bring purchased electricity into our control area, potentially requiring us to curtail or interrupt our customers as permitted by our tariffs and terms and conditions of service. Purchased power for the year ended December 31, 2006 comprised approximately 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.

Energy Marketing Activities

We engage in both financial and physical trading with the goal of increasing profits, managing commodity price risk and enhancing 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. KGE owns a 47% interest in Wolf Creek, or 548 MW, which represents 9% of our total generating capacity. KCPL owns an equal 47% interest, with 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 March 2011. During 2006, we entered into contracts with suppliers which will cover a majority of Wolf Creek’s uranium and conversion needs through 2017. Fabrication and enrichment requirements are under contract through 2024.

Because 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 agreements in the ordinary course of business. We believe Wolf Creek is not substantially dependent on these agreements. However, contraction and consolidation among suppliers of these commodities and services, increasing worldwide demand, 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, volumes under these contracts in the event of a protracted supply disruption. We believe this uncertainty is not unique in the nuclear industry.

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 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 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 term of its existing operating 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 creating new disposal capability 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 34 days in 2006 for its fifteenth scheduled refueling and maintenance outage. During outages at the plant, we met our electric demand primarily with our other generating units and by purchasing power. As provided by the KCC, we defer and amortize evenly the incremental maintenance costs incurred for planned refueling outages over the unit’s 18 month operating cycle. Wolf Creek is next scheduled to be taken off-line in the spring of 2008 for its sixteenth 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 involves the review 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 site study of decommissioning costs, including the costs of decontamination, dismantling and site restoration, our share of such costs is 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. We believe that the KCC approved funding level will also be sufficient to meet the NRC minimum financial assurance requirement. Our 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.

We recovered in rates and deposited in an external trust fund approximately $3.9 million for nuclear 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 as of December 31, 2005.

Competition and Deregulation

The Federal Energy Regulatory Commission (FERC) requires owners of regulated transmission assets to allow third party wholesale providers of electricity nondiscriminatory access to their transmission systems to transport electric power to wholesale customers. FERC also requires us to provide transmission services to others under terms comparable to those we allow ourselves. In December 1999, FERC issued an order encouraging the formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating competitive wholesale power markets.

Regional Transmission Organization

We are a member of the SPP, the RTO in our region. On September 19, 2006 the KCC approved an order allowing us to transfer functional control of our transmission system to the SPP under its membership agreement and applicable tariff. The SPP coordinates the operation of our transmission system within an interconnected transmission system that covers all or portions of eight states. The SPP collects revenues for the use of each transmission owner’s transmission system. Transmission customers transmit throughout the entire SPP system power purchased and generated for sale or bought for resale in the wholesale market. Transmission capacity is sold on a first come/first served non-discriminatory basis. All transmission customers are charged rates applicable to the transmission system in the zone where energy is delivered, including transmission 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, although we expect higher costs due to the administrative 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 to implement a real-time market to accommodate financial settlement of energy imbalances within the SPP region. An energy imbalance exists when a market participant’s actual power inputs to or outputs from the transmission network differ from the level of inputs and 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 market protocols. The SPP implemented the real-time energy imbalance market on February 1, 2007. At this time we are unable to determine what impact this may have on our results of operations.

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Regulation and Rates

Kansas law gives the KCC 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.

FERC Proceedings

Request for Change in Transmission Rates: On May 2, 2005, we filed applications with FERC that proposed a formula transmission rate providing for annual adjustments to our transmission costs. This is consistent with our proposals filed with the KCC on May 2, 2005 to charge retail customers separately for transmission service through a transmission delivery charge. The proposed FERC transmission rates became effective, subject 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 and interest on that amount.

Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. These laws and regulations relate primarily to discharges into the air, air quality, discharges of effluents into water, 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. The 2005 KCC Order established the environmental cost recovery rider (ECRR), which will allow for the timely inclusion in rates of capital investments we make related directly 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 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 prescribed 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 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 in the market in which such allowances are traded. In 2006, we had emissions allowances adequate to meet planned generation and we expect to have enough in 2007. In the future we may need to purchase additional allowances. We expect to recover the cost of emission allowances through the RECA. The pricing of emissions allowances is unpredictable and may change over time.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule. The rule caps permanently, and seeks to reduce, the amount of mercury that 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 equipment at our coal-fired units. Several different environmental groups and states are challenging this rule in court, which could potentially delay 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, we will need to have installed and certified by January 1, 2009, continuous emissions mercury monitoring systems on each coal-fired unit. We do not know what the costs to comply with the Clean Air Mercury Rule will be, but we believe they could be material.

Environmental 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)). Proposals and bills in 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 installing additional equipment related to emissions controls at La Cygne in 2005. We currently expect our share of these capital costs through the scheduled completion in 2009 to be approximately $232.5 million. Additionally, we have identified the potential for up to $512.4 million of capital expenditures for environmental projects at our other power plants during the next seven to ten years. Our 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 and other factors. In addition to the capital investment, when we install such equipment, we will also incur significant annual expense to operate and maintain the equipment and the operation of the equipment reduces net production from our plants. The ECRR allows for the timely inclusion in rates of capital expenditures tied directly 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 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 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. 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. We have sole responsibility for remediation with respect to three sites.

Our liability for former manufactured gas sites in Missouri is limited by an environmental indemnity with the purchaser of our former Missouri assets in the amount of $7.5 million.

SEASONALITY

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

EMPLOYEES

As of February 15, 2007, we had 2,223 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 1,279 employees as of February 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.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.

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Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the energy use of our customers. The value of our common stock 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 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 that left our base rates virtually unchanged but approved various changes to our rate structure that allow some adjustment to our prices. The KCC approved the RECA, which allows us to recover cost of fuel for generation and purchased power expense (less margins earned on wholesale sales). It also authorized us to implement the ECRR, which allows us to change our rates to reflect the impact of capital expenditures made to upgrade our equipment to environmental standards required by the Clean Air Act.

Our Costs May Not be Fully Recovered in Retail Rates

Except 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. We may apply to change 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 maintenance programs 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 meet our sales obligations. In addition, equipment failure can limit our ability to make opportunistic sales to wholesale customers.

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

Coal deliveries from the PRB region of Wyoming, the primary source for our coal, can be interrupted or can be slowed due to rail traffic congestion, equipment or track failure, or due to loading problems at the mines. This may require that we implement coal conservation efforts and/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 opportunistic 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, along with the prices and price volatility of fuel and wholesale 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 in our rates the costs that we incur to comply with environmental regulations, we can provide no assurance that we will be able to fully and timely recover 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 Statement of Financial Accounting Standard (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business. As of December 31, 2006, we had recorded $476.0 million of regulatory assets, net of regulatory liabilities. In the event we determined that we could no longer apply the principles of SFAS No. 71, either as: (i) a result of the establishment of retail competition in our service territory; (ii) a change in the regulatory approach for setting rates from cost-based ratemaking to another form of ratemaking; or (iii) other regulatory actions that restrict cost recovery to a level insufficient to recover 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 Associated 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 more 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 into the wholesale markets. If we were not permitted by the KCC to recover these costs, such events would likely have an adverse impact on our consolidated financial condition.

None.

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We own approximately 6,100 miles of transmission lines, approximately 23,700 miles of overhead distribution lines and approximately 3,800 miles of underground distribution lines.

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

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 – Department of Labor Investigation,” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

None.

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PART II

STOCK PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock during the period that began on December 31, 2001 and ended on December 31, 2006 to the Standard & Poor’s 500 Index and the Standard & Poor’s Electric Utility Index. The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.

STOCK TRADING

Our common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 15, 2007, there were 26,449 common shareholders of record. For information regarding quarterly common stock price ranges for 2006 and 2005, see Note 23 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

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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 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. During 2006 our board of directors declared four quarterly dividends, each at $0.25 per share, reflecting an annual dividend of $1.00 per share. On February 21, 2007, our board of directors declared a quarterly dividend of $0.27 per share on our common stock payable to shareholders on April 2, 2007. The indicated annual dividend rate is $1.08 per share.

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 were not limited by any such restrictions during 2006. 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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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 2006, and our operating results for the years ended December 31, 2006, 2005 and 2004. 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 or may impact us and our operations since January 1, 2006:

Changes in Rates

In accordance with a 2003 KCC Order, on May 2, 2005, we filed applications with the KCC for it to review our retail electric rates. The 2005 KCC Order authorized changes in our 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 Kansas Court of Appeals challenging various aspects of the 2005 KCC Order. On July 7, 2006, the Kansas Court of Appeals reversed and remanded for further consideration by the KCC three elements of the 2005 KCC Order. The balance of the 2005 KCC Order was upheld.

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On February 8, 2007, the KCC issued an order in response to the Kansas 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 charge, ruled that it 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 inclusion in depreciation rates of a component for terminal net salvage. The February 8, 2007 KCC Order requires us to refund to our customers the amount we have collected related to terminal net salvage. We have recorded a regulatory liability at December 31, 2006 in the amount of $16.4 million related to this item.

Increased Capacity and Future Plans

On October 31, 2006, we purchased a 300 MW electric generation facility and related assets from ONEOK Energy Services Company, L.P. (OESC) for $53.0 million. As part of this transaction, we entered into an agreement to provide OESC with 75 MW of capacity through 2015.

In August 2006, we announced plans to build a new natural gas-fired combustion turbine peaking power plant near Emporia in Lyon County, Kansas. We expect the new plant, which we have named the Emporia Energy Center, to have an initial generating capacity of up to 300 MW, with additional capacity to be added in a second phase, bringing the total capacity to approximately 600 MW. We expect the total investment in the plant to be about $318 million. We plan to begin construction on the new plant in the spring of 2007. The initial phase of the plant is scheduled to begin operation in the summer of 2008.

In September 2006, we announced plans to build a transmission line from our Gordon Evans Energy Center northwest of Wichita, Kansas, to a new substation near Hutchison, Kansas, then onto our Summit substation near Salina, Kansas, a distance totaling approximately 86 miles. In January 2007, we filed an application with the KCC to request permission to build the line. Kansas law requires the KCC to issue an order within 120 days of our filing regarding our application. If the KCC issues a permit for us to proceed, we expect to complete construction in 2009. Our preliminary cost estimate for the project is $80 million to $100 million. This estimate could change materially as engineering and construction proceed. In addition to this line, we plan additional expansions to our electric transmission network in Kansas. These include a new line from our Rose Hill substation near Wichita to the Kansas-Oklahoma border, where we expect to interconnect with new facilities built by an Oklahoma-based utility, and a new line from our Jeffrey Energy Center to an existing substation about 15 miles south of Topeka, Kansas.

Convictions of David C. Wittig and Douglas T. Lake Overturned

On September 12, 2005, David C. Wittig, our former chairman of the board, president and chief executive officer, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, were convicted on various criminal charges by a jury in a trial held in U.S. District court in Kansas. The jury also determined that Mr. Wittig and Mr. Lake should forfeit to the United States certain property that it determined was derived from their criminal conduct. The court subsequently awarded us certain of the property forfeited by Mr. Wittig and Mr. Lake. On January 5, 2007, the U.S. Tenth Circuit Court of Appeals overturned these convictions and forfeiture orders. At December 31, 2006, we had accrued liabilities totaling approximately $74.8 million for compensation not yet paid to Mr. Wittig and Mr. Lake under various plans, and we had also accrued approximately $9.9 million for legal fees and expenses incurred by Mr. Wittig and Mr. Lake in the defense of these charges and related appeals. We believe Mr. Wittig and Mr. Lake are not entitled to this compensation. This dispute, and claims Mr. Wittig and Mr. Lake have made against us, are the subject of an arbitration that has been stayed pending the resolution of the criminal proceedings. We also believe the amounts sought by Mr. Wittig and Mr. Lake for legal fees and expenses are unreasonable. These disputes are also the subject of litigation. We are unable to predict whether the government will retry the criminal charges against Mr. Wittig and Mr. Lake or the outcome of these matters, including their ultimate impact on our results of operations. For additional information, see Note 18 of the Notes to Consolidated Financial Statements, “Potential Liabilities to David C. Wittig and Douglas T. Lake.”

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Coal Inventory and Delivery

Coal deliveries from the Powder River Basin region of Wyoming to our coal-fired generating stations improved in 2006; however, they continue to be slower than historical averages due primarily to issues at the 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. We may continue to use these measures as conditions warrant. The compensating measures include, but are not limited to: reducing coal consumption during certain periods, revising normal operational dispatch of our generating units, purchasing power from others, reducing wholesale sales and leasing additional rail cars. The effects of additional purchased power expense and the reduction in sales due to slower coal deliveries have been partially offset by higher 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 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 utility rates. Regulatory liabilities represent probable future reductions in revenue or refunds to 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.

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”, SFAS No. 106, “Employers’ Accounting for Post-retirement Benefits Other Than 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 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 2004. These amounts reflect the pension expense of Westar Energy and our 47% responsibility for the pension expense of Wolf Creek. Pension expense increases are due primarily to the amortization of investment losses from prior years that are recognized on a rolling four-year average basis and changes in assumptions including lower discount rates, lower returns on assets, increases in salaries 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 the discount rate and rate of return on plan assets on our post-retirement benefit plans other than pension plans.

Revenue Recognition – Energy Sales

We record 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 the 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 demands, weather, line losses and changes in the composition of customer classes. We had estimated unbilled revenue of $38.4 million as of December 31, 2006 and $42.1 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 as gains or losses in the period of change. With the exception of contracts for fuel 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 is 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 value 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 as of December 31, 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 losses, operating losses and tax credit carryforwards. However, when we believe we do not or will not have sufficient 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 available evidence that it is unlikely that we will realize some portion or all of the deferred tax 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 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 revenue subject to refund.

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

Market-based wholesale: Sales of energy to wholesale customers, the rates for which are generally based on prevailing market prices as allowed by our FERC approved market-based tariff, 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: (i) transactions based on market prices with volumes not related to the production of our generating assets or the demand of our retail customers; (ii) financially settled products and physical transactions sourced outside our control area; and (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, 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 economy of our service area 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. Hot summer temperatures and cold winter temperatures prompt more demand, especially among our residential customers. Mild weather serves 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.

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The following table reflects changes in electric sales volumes, as measured by thousands of megawatt hours (MWh) of electricity. No sales volumes are shown for energy marketing, transmission or other. Energy marketing activities are unrelated to the amount of electricity we generate at our generating plants.

The increase in retail sales reflects the change in rates, including the effect of implementing the RECA, and warmer weather. When measured by cooling degree days, the weather during 2006 was 2% warmer than during 2005 and approximately 16% warmer than the 20-year average. The increase in industrial sales was due primarily to additional oil refinery load. The change in other retail sales reflects the recognition in 2006 of revenue subject to refund, of which: (i) $19.9 million is due to the difference between estimated fuel and purchased power costs billed to our customers and actual fuel and purchased power costs incurred for our Westar Energy customers; (ii) $3.3 million is due to amounts associated with a transmission delivery charge approved by the KCC in its 2005 Order; (iii) $4.0 million collected for property taxes in excess of our actual property taxes obligations; and (iv) $16.4 million related to amounts we collected in rates related to terminal net salvage that the KCC’s February 8, 2007 Order requires us to refund. The revenue subject to refund was partially offset by our having stopped accruing for rebates to customers in December 2005.

We made tariff-based sales in 2006 at an average price that was about 5% higher than the price of these sales in 2005. We attribute about $1.3 million, or 14%, of the increase in tariff-based wholesale sales to higher prices reflecting an adjustment for our fuel costs as permitted in FERC tariffs.

Our market-based wholesale sales and sales volumes decreased in 2006 due primarily to our having conserved coal inventories, but the average price per MWh that we received for these sales in 2006 was about 7% higher than in 2005.

The change in fuel and purchased power expense is the result of changing volumes produced and purchased, prevailing market prices and contract provisions that allow for price changes. We burned about 4% less fuel in our generating plants in 2006, due primarily to our having conserved coal inventories. We also used less expensive generation. In addition, during 2006 we deferred as a regulatory asset $6.9 million for the difference between the estimated fuel and purchased power costs that we billed our KGE customers and our higher actual fuel and purchased power costs that we are allowed to collect under the terms of the RECA. As a result, our fuel expense was $45.5 million lower in 2006 than in 2005. We also experienced a $1.2 million increase in our purchased power expense due primarily to our having purchased 9% greater volumes than in 2005.

We experienced an increase in our operating and maintenance expense due primarily to four factors: (i) the amortization of $10.7 million of previously deferred storm restoration expenses as authorized by the 2005 KCC Order; (ii) a $9.9 million increase in SPP network transmission costs; (iii) a $4.7 million increase in taxes other than income taxes due primarily to higher property taxes; and (iv) an increase in maintenance expenses for outages at La Cygne and the Gordon Evans Energy Center. These higher expenses were partially offset by a $5.4 million reduction in the lease expense related to La Cygne unit 2. Operating and maintenance expense in 2005 included a $10.4 million loss as a result of the decrease in the present value of previously disallowed plant costs associated with the original construction of Wolf Creek due to the extension of the recovery period.

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We experienced an increase in our depreciation and amortization expense of $29.7 million. This increase was due primarily to the reduction of depreciation expense of $20.1 million in 2005 due to the establishment of a regulatory asset for the differences between the depreciation rates we used for financial reporting purposes and the depreciation rates authorized by the KCC for the period of August 2001 to March 2002. Provisions of the 2005 KCC Order allowed us to record this regulatory asset.

Selling, general and administrative expenses increased due primarily to increased employee pension and benefit costs. Partially offsetting these increases were lower legal fees associated with matters having to deal with former management and a decline in insurance costs.

Other income increased due primarily to corporate-owned life insurance. We received $16.4 million in income from corporate-owned life insurance in 2006 compared to $7.2 million in 2005. Associated with our having terminated an accounts receivable sales facility we experienced a $3.9 million decrease in other expense.

Interest expense decreased due primarily to a $16.7 million reduction in interest expense on long-term debt due primarily to a lower long-term debt balance and lower interest rates resulting from the refinancing activities discussed in detail in “—Liquidity and Capital Resources – Debt Financings.” This decline was partially offset by an increase of $6.3 million in interest expense on short-term debt due to increased borrowings under our revolving credit facility.

The decrease in income tax expense is due primarily to the utilization of previously unrecognized capital loss carryforwards to offset realized capital gains and increases in non-taxable income from corporate-owned life insurance.

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2005 Compared to 2004

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