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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

(Title of Class)

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

Large accelerated filer    X      Accelerated filer              Non-accelerated filer               Smaller reporting company          

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 $2,324,082,258 at June 30, 2008.

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

DOCUMENTS INCORPORATED BY REFERENCE:

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning 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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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.

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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 679,000 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

Changes in Rates

We filed an application with the Kansas Corporation Commission (KCC) in May 2008 to increase retail rates by $177.6 million per year. The primary drivers for this application were investments in natural gas generation facilities, wind generation facilities and other capital projects, costs attributable to the 2007 ice storm, higher operating costs and an update of our capital structure. On October 27, 2008, all parties to the proceeding filed an agreement with the KCC supporting a $130.0 million annual increase in our retail rates. On January 21, 2009, the KCC issued an order approving the settlement agreement and the new retail rates became effective on February 3, 2009.

The KCC and Federal Energy Regulatory Commission (FERC) also adjust our rates through the use of rate mechanisms that are designed to track certain portions of the costs of providing utility service. For additional information, see Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.”

Economic Conditions

Global and U.S. economic conditions throughout 2008 have begun to impact certain of our industrial and commercial customers and may affect our residential business. Kansas companies are experiencing reduced production and have announced significant employee layoffs. Kansas is experiencing an increase in unemployment claims and the unemployment rate. We cannot determine when these conditions may reverse or whether and to what extent they may affect our results of operations.

Tax Settlements

In February 2008, we reached a settlement with the Internal Revenue Service (IRS) on issues principally related to the method used to capitalize overheads to electric plant for years 1995 through 2002. This settlement resulted in a 2008 net earnings benefit of approximately $39.4 million, including interest, due to the recognition of previously unrecognized tax benefits. The recognition of these previously unrecognized tax benefits resulted in earnings of $0.38 per share for the year ended December 31, 2008.

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In January 2009, we reached a settlement with the IRS associated with the re-characterization of the loss we incurred on the sale of Protection One, Inc. (Protection One) from a capital loss to an ordinary loss. This settlement will result in a first quarter 2009 net earnings benefit from discontinued operations of approximately $32.5 million due to the recognition of previously unrecognized tax benefits in accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109.”

New Construction Plans

We are making and will continue to make significant investments in new generation, new transmission and air emission controls at existing fossil-fueled power plants.

During 2008, we made capital expenditures of $257.2 million at our power plants for air emission controls. We have identified the potential for us to make up to an additional $1.3 billion of capital expenditures at our power plants for air emissions projects over the next six years.

We have been working with third parties to develop approximately 300 megawatts (MW) of wind generation facilities at three different sites in Kansas. Under the terms of the agreements, we will own approximately half of the wind generation facilities at an expected cost of approximately $282.0 million and will purchase energy produced by the wind generation facilities under twenty year supply contracts for the other half. One of the facilities from which we purchase energy began producing energy in December 2008 and we expect the other two to begin producing energy in early 2009.

On February 12, 2009, we announced that we are seeking bids for as much as 500 MW of additional renewable energy resources. We requested bids contemplating for potentially up to 200 MW of the generation being online by late 2010 with the remainder being potentially online by late 2013. We and our regulators have not yet concluded whether any additional renewable resources will be added.

We are constructing a 345 kilovolt (kV) transmission line from our Gordon Evans Energy Center northwest of Wichita, Kansas, to a new substation near Hutchinson, Kansas, then on to our Summit substation near Salina, Kansas, a distance totaling approximately 100 miles. We completed construction of the first segment in December 2008 and expect the second segment to be completed by June 2010. We expect the total investment in the line and substations to be approximately $200.0 million.

In addition to the transmission line described above, we also plan to construct a new 345 kV line from a substation near Wichita to the Kansas-Oklahoma border, where we will interconnect with new facilities being built by an Oklahoma utility. The preliminary estimate of the investment in the line is approximately $90.0 million, which is subject to change pending final engineering design, labor and materials, among other factors. We expect to begin construction in 2010.

In 2008, we completed the first phase of our Emporia Energy Center, a new natural gas-fired peaking power plant consisting of seven combustion turbines located near Emporia in Lyon County, Kansas, comprising approximately 350 MW of capacity. We expect to complete construction of the second phase, consisting of two generating units that will add an additional approximately 320 MW of generating capacity, early in 2009 for a total investment of about $318.0 million.

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In May 2008, we and Electric Transmission America, LLC formed Prairie Wind Transmission, LLC (Prairie Wind Transmission), a joint venture company of which we own 50%. Prairie Wind Transmission is proposing to construct approximately 230 miles of 765 kV transmission facilities in Kansas extending west from near Wichita to near Dodge City and then south-southwest to the Kansas-Oklahoma border. On December 2, 2008, FERC approved a number of key rate components related to these transmission facilities and set aside for hearing the establishment of a formula rate and associated protocols. Should Prairie Wind Transmission receive the necessary regulatory approvals from the KCC and FERC, the facilities are expected to be in service by the end of 2013, contingent on a number of factors including the availability and cost of capital, not all of which are under our control. We will incur significant future capital expenditures related to this joint venture if Prairie Wind Transmission receives regulatory approval to build the transmission facilities.

OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 366,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 313,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 31 cities in Kansas and four electric cooperatives in Kansas pursuant to contracts of various lengths. 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 electricity in areas outside our retail service territory.

We have 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 most of our retail customers. As a result of the January 21, 2009, KCC Order (2009 KCC Order), we will bill our customers for fuel on a quarter ahead estimate beginning approximately March 1, 2009. The RECA provides for an annual review by the KCC to reconcile estimated and actual fuel and purchased power costs. The KCC uses this same mechanism as the means by which we refund to customers the margins realized from market-based wholesale sales.

Generation Capacity

We have 6,508 MW of accredited generating capacity in service, of which 2,578 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 2008 peak system net load of 4,754 MW occurred on August 4, 2008. This included 107 MW of potentially interruptible load. Our net generating capacity, combined with firm capacity purchases and sales and the ability to interrupt 107 MW of load, provided a capacity margin of 18% above system peak responsibility at the time of our 2008 peak system net load.

Under wholesale agreements, we provide firm 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 MMBtu, our 2008 fuel mix was 79% coal, 13% nuclear and 7% natural gas, with diesel and oil making up less than 1%. In 2009 we expect to use higher percentages of coal and nuclear as we do not expect to experience extended outages at our coal plants or Wolf Creek in 2009. There were extended outages at some of our coal plants and Wolf Creek in 2008. As a result of our new wind generation facilities, 2009 will be the first year in which we expect to produce a significant amount of wind energy. 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 2,164 MW, of which we own and lease a combined 92% share, or 1,991 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 in excess of 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. We made a scheduled re-pricing in 2008. The next re-pricing for those quantities over the scheduled annual minimum will occur in 2013.

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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 2008 was approximately $1.57 per MMBtu, or $26.25 per ton.

La Cygne Generating Station: The two coal-fired units at La Cygne Generating Station (La Cygne) have an aggregate generating capacity of 1,418 MW, of which we own or lease a 50% share, or 709 MW. La Cygne unit 1 uses a blended fuel mix containing approximately 90% PRB coal and 10% Kansas/Missouri coal, the latter of which is purchased from time to time from local Kansas and Missouri producers. 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.

During 2008, the average delivered cost of all coal burned at La Cygne unit 1 was approximately $1.31 per MMBtu, or $21.24 per ton. The average delivered cost of coal burned at La Cygne unit 2 was approximately $1.18 per MMBtu, or $19.65 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 770 MW. We purchase coal under a contract with Arch Coal, Inc. (Arch). The current contract with Arch is expected to provide 100% of the coal requirement for these energy centers through 2010.

BNSF transported coal for these energy centers from Wyoming under a contract that expired in December 2008. We have reached a mutual agreement of understanding with BNSF for the continuing provision of coal transportation to these energy centers until we finalize a long-term contract.

During 2008, the average delivered cost of all coal burned in the Lawrence units was approximately $1.22 per MMBtu, or $21.56 per ton. The average delivered cost of all coal burned in the Tecumseh units was approximately $1.24 per MMBtu, or $21.86 per ton.

Natural Gas

We use natural gas as a primary fuel at our Gordon Evans, Murray Gill, Neosho, Abilene, Hutchinson, Spring Creek and Emporia Energy Centers, at the State Line facility and in the gas turbine units at Tecumseh 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 2008, we purchased 22.1 million MMBtu of natural gas for a total cost of $172.0 million. Natural gas accounted for approximately 7% of our total MMBtu of fuel burned during 2008 and approximately 31% of our total fuel expense. From time to time, we may purchase derivative contracts 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.”

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We maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. (ONEOK). The Abilene Energy Center is covered under a standard tariff as a large industrial transportation customer while the Hutchinson Energy Center is covered under a rate agreement that expires on April 30, 2009. We plan to renegotiate the agreement for the Hutchinson Energy Center prior to its expiration. We meet a portion of our natural gas transportation requirements for the Gordon Evans, Murray Gill, Lawrence, Tecumseh and Emporia Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Gas Pipeline (SSCGP). We meet all of the natural gas transportation requirements for the State Line facility through a firm natural gas transportation agreement with SSCGP. The firm transportation agreement that serves the Gordon Evans and Murray Gill Energy Centers has been restructured and extended through April 1, 2020. The agreement for the State Line facility extends through June 1, 2016, while the agreement for the Emporia Energy Center is in place until December 1, 2028, and is renewable for five-year terms thereafter. 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.

Diesel and Oil

Once started with natural gas, the steam units at our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn No. 6 oil or natural gas. We only burn No. 6 oil when natural gas is unavailable. During 2008, we did not burn any No. 6 oil.

We also use No. 2 diesel 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 No. 2 diesel in the spot market. 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.

During 2008, we burned 0.3 million MMBtu of diesel at a total cost of $5.6 million. Diesel accounted for less than 1% of our total MMBtu of fuel burned during 2008 and approximately 1% of our total fuel expense. For additional information on our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Other Fuel Matters

The table below provides our weighted average cost of fuel, including transportation costs.

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Purchased Power

We purchase electricity in addition to generating it ourselves. Factors that cause us to make such purchases include planned and unscheduled outages at our generating plants, prices for wholesale energy compared to generation costs, 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. Purchased power for the year ended December 31, 2008, comprised approximately 20% of our total fuel and purchased power expenses. The weighted average cost of purchased power was $58.96 per megawatt hour (MWh) in 2008, $61.04 per MWh in 2007 and $54.90 per MWh in 2006.

Energy Marketing Activities

We engage in both financial and physical trading with the objective of increasing profits, managing commodity price risk and enhancing system reliability. We trade electricity and other energy-related products using a variety of financial instruments, including future contracts, options and swaps, and we trade energy commodity contracts.

Nuclear Generation

General

Wolf Creek is a 1,160 MW nuclear power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or 545 MW, which represents 8% of our total generating capacity. KCPL owns an equal 47% interest, with Kansas Electric Power Cooperative, Inc. 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. In November 2008, the NRC approved WCNOC’s request and Wolf Creek’s operating license was extended until 2045.

Fuel Supply

The owners of Wolf Creek have on hand or under contract all of the uranium and conversion services needed to operate Wolf Creek through March 2011 and approximately 87% of uranium and conversion services after that date through September 2018. The owners also have under contract 100% of the uranium enrichment and fabrication required to operate Wolf Creek through March 2025.

Because of a production delay at a mine from which Wolf Creek expected to receive future supplies of uranium, it is possible that contracted uranium deliveries scheduled for 2010 and some years beyond could be reduced, necessitating an increase in the amount of uranium planned for purchase in those years. Wolf Creek’s on-going operations strategies, including previous acquisition of inventory, are expected to minimize the impact of such reductions.

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.

Radioactive Waste Disposal

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. Our share of the fee was $3.5 million in 2008, $4.4 million in 2007 and $4.1 million in 2006 and is calculated as one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers. We include these costs in fuel and purchased power expense.

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In 2002, the Yucca Mountain site in Nevada was approved for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. This action allows the DOE to apply to the NRC to license the project. On June 3, 2008, the DOE submitted a license application to the NRC seeking authorization to construct the nuclear waste repository at the Yucca Mountain site. 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.

Wolf Creek disposes of all classes of its low-level radioactive waste at existing third-party repositories. One of those repositories was located in Barnwell, South Carolina. However, as of July 1, 2008, the State of South Carolina no longer accepts waste from generators other than those located in South Carolina, Connecticut, and New Jersey – the three states that make up the Atlantic Interstate Low-Level Radioactive Waste Management Compact. We expect that another site in the state of Utah will remain available to Wolf Creek. 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. An initial effort in the 1990s to license the construction of a disposal facility in Nebraska failed and the Central States Compact Commission revoked Nebraska’s membership in the Central States Compact. There has not been another effort to develop a disposal facility in the Central States Compact region.

Outages

Wolf Creek operates on an 18-month planned refueling and maintenance outage schedule. Wolf Creek was shut down for 55 days in 2008 for refueling and maintenance. During outages at the plant, we meet 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 fall of 2009 for refueling and maintenance.

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. 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 next review is scheduled to occur in 2009.

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The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the revised nuclear decommissioning study including the estimated costs to decommission the plant. 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. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations, technologies 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 is 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 operating license expires in 2045. 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 were 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 for nuclear decommissioning approximately $2.9 million in 2008 and 2007 and $3.9 million in 2006. We record our investment in the nuclear decommissioning fund at fair value. The fair value approximated $85.6 million as of December 31, 2008 and $122.3 million as of December 31, 2007. During 2008, the value of these financial assets declined significantly. As a result, we will likely have to contribute additional amounts to the nuclear decommissioning fund. We expect to collect those amounts from our customers.

Competition and Deregulation

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. Furthermore, FERC issued an order encouraging the formation of regional transmission organizations (RTO). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating competitive wholesale power markets.

Regional Transmission Organization

We are a member of the Southwest Power Pool (SPP), the RTO in our region. 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.

Real-Time Energy Imbalance Market

On February 1, 2007, the SPP implemented the real-time energy imbalance market as required by FERC to accommodate financial settlement of energy imbalances within the SPP region. The objective of the real-time market system is to permit an efficient balancing of energy production and consumption through the use of a least cost economic dispatch system. It also provides a ready market for the economical purchase and sale of excess energy maximizing the available transmission system. The company participates in this market.

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.

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FERC Proceedings

Requests for Changes in Transmission Rates

On December 2, 2008, FERC issued an order approving a settlement of our transmission formula rate that allows us to include our anticipated transmission capital expenditures for the current year in our transmission formula rate, subject to true up. In addition to the true up, we expect to update our transmission formula rate in January of each year to reflect changes in our projected operating costs and investments.

On March 24, 2008, FERC issued an order that granted our requested incentives of an additional 100 basis points above the base allowed return on equity (ROE) and a 15-year accelerated recovery for an approximately 100 mile, 345 kV transmission line that will run from near Wichita, Kansas, to near Salina, Kansas. We completed construction of the first segment of this line in December 2008 and expect the second segment to be completed by June 2010. We estimate the line will cost approximately $200.0 million.

In November 2007, we filed applications with FERC that proposed changes in the capital structure used in our transmission formula rate. FERC accepted the proposed changes and the rate change went into effect on June 1, 2007. At December 31, 2008, we had a $2.8 million refund obligation related to this matter, which includes the amount we have collected since June 1, 2007, plus interest on that amount.

On May 2, 2005, we filed applications with FERC that proposed a transmission formula rate providing for annual adjustments to our transmission tariff. 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 (TDC). In November 2007, FERC approved a settlement providing for the rate change effective December 1, 2005, and a refund to customers of $3.4 million.

Request for Increase in Revolving Credit Facility

On January 11, 2008, we filed a request with FERC for authority to issue short-term securities and to pledge KGE mortgage bonds in order to increase the size of Westar Energy’s revolving credit facility to $750.0 million. On February 15, 2008, FERC granted our request. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Resources” for more information.

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Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting power plants are overlapping, complex, subject to changes in interpretation and implementation, and have tended to become more stringent over time. 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, disposal and clean-up 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, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or sanctions may not be recoverable in rates. We have incurred and will continue to incur capital and other expenditures to comply with environmental laws and regulations. Certain of these costs are recoverable through the environmental cost recovery rider (ECRR), which allows for the more timely inclusion in retail rates of capital investments related directly to environmental improvements required by the Clean Air Act as well as many of the costs related to compliance with other environmental laws and regulations. However, there can be no assurance that we will be able to recover all such costs from our customers or that the costs to comply with existing or future environmental laws and regulations will not have a material adverse effect on our consolidated financial statements.

Air Emissions

The Clean Air Act, state laws and implementing regulations impose, among other things, limitations on pollutants generated during our operations, 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 and natural gas and have equipped some of 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 certain emissions. We have installed continuous emissions monitoring and reporting equipment in order to meet these requirements.

Title IV of the Clean Air Act created an SO₂ allowance and trading program as part of the federal acid rain program. Under the allowance and trading program, the Environmental Protection Agency (EPA) allocated annual SO₂ allowances for each affected 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 2008, we had SO₂ allowances adequate to meet planned generation and we expect to have enough in 2009. In the future if we need to purchase additional allowances our operating costs would increase. We expect to recover the cost of emission allowances through the RECA although there are no guarantees we will be able to do so. The price of emissions allowances is determined by market forces and changes over time.

On February 28, 2008, we reached an agreement with the KDHE to implement a plan to improve efficiency and to install new equipment to reduce regulated emissions from Jeffrey Energy Center. The projects are designed to meet requirements of the Clean Air Visibility Rule and reduce emissions over our entire generating fleet by eliminating more than 70% of SO₂ and reducing nitrous oxides between 50% and 65%.

On March 15, 2005, the EPA issued the Clean Air Mercury Rule. Beginning in 2010, the rule caps permanently and reduces the amount of mercury that may be emitted from coal-fired power plants. However, on February 8, 2008, the U.S. District Court of Appeals for the District of Columbia vacated the Clean Air Mercury Rule. While the ultimate impact of this ruling on our operations is currently unknown, we believe that mercury emissions controls may be required in the future and that the costs to comply with these requirements may be material.

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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 Costs

We have identified the potential for us to make up to $1.3 billion of capital expenditures at our power plants for environmental air emissions projects during the next six years. This estimate could materially increase or decrease depending on the timing and the nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the resolution of the EPA New Source Review Investigation (NSR Investigation) and the related Department of Justice (DOJ) lawsuit described below. In addition to the capital investment, in the event we install new equipment as a result of the NSR Investigation and the related DOJ lawsuit, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce net production from our power plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. In addition, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of these capital investments.

The ECRR allows for the more timely inclusion in retail rates of capital expenditures tied directly to environmental improvements, including those required by the Clean Air Act. However, increased operating and maintenance costs, other than expenses related to production-related consumables, can be recovered only through a change in base rates.

New Source Review Investigation

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 the New Source Review permitting program 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 reasonably have been expected to result in a significant net increase in emissions. The New Source Review program requires companies to obtain permits and, if necessary, install control equipment to address 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 certain requirements of the New Source Review program. On February 4, 2009, the DOJ filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. A decision in favor of the DOJ and the EPA, or a settlement prior to such a decision, if reached, 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. Our ultimate costs to resolve the NSR Investigation and the related DOJ lawsuit could be material. We believe that costs related to updating or installing emissions controls would qualify for recovery in the prices we are allowed to charge our customers. If, however, a penalty is assessed against us, 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.

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Manufactured Gas Sites

We have been identified as being responsible for the clean-up of 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, 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 the former manufactured gas sites identified in Missouri is limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of our former Missouri assets.

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 18, 2009, we had 2,415 employees. In 2008, we negotiated a three-year contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers that extends through June 30, 2011. The contract covered 1,343 employees as of February 18, 2009.

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 statements. 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 and FERC

The KCC and FERC regulate many aspects of our business and operations, including the rates that we charge customers for electric service. Retail rates are set by the KCC while wholesale and transmission rates are set by FERC. Both the KCC and FERC use 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 and FERC set rates at a level calculated to recover such costs and a permitted return on investment. On January 21, 2009, the KCC authorized a $130.0 million increase in our retail rates to reflect our investment in natural gas generation facilities, wind generation facilities and other capital projects, costs attributable to the 2007 ice storm, higher operating costs and an update of our capital structure. The new retail rates became effective on February 3, 2009.

Our Costs May Not be Fully Recovered in Rates

Except to the extent the KCC and FERC permit us to modify our prices by using specific adjustments and riders, such as the RECA, TDC and ECRR, 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 our rates be reviewed for possible adjustment.

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 extended or unplanned outages because of equipment failure, weather, failure by our contractors or subcontractors to meet commitments and other factors largely beyond our control. In such events, we must either produce replacement power from our other, usually less efficient, units or purchase power from others at unpredictable and potentially higher costs in order to meet our sales obligations. In addition, such events 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 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 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 financial statements. 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 Relating to Environmental Matters

Under Section 114, the EPA is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to the New Source Review permitting program 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 reasonably have been expected to result in a significant net increase in emissions. The New Source Review program requires companies to obtain permits and, if necessary, install control equipment to address 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 certain requirements of the New Source Review program. On February 4, 2009, the DOJ filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. A decision in favor of the DOJ and the EPA, or a settlement prior to such a decision, if reached, 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. Our ultimate costs to resolve the NSR Investigation and the related DOJ lawsuit could be material. We believe that costs related to updating or installing emissions controls would qualify for recovery in the prices we are allowed to charge our customers. If, however, a penalty is assessed against us, 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.

Our activities are subject to extensive and changing environmental regulation by federal, state and local governmental authorities, particularly relating to air emissions. In addition to laws currently in effect, numerous laws and regulations have been enacted and proposed relating to increasing national and international concern about possible global warming caused by the atmospheric release of CO₂ and other gases by industrial and other sources, including the utility industry. On November 15, 2007, the governors of six Midwestern states, including Kansas, signed the Midwest Greenhouse Gas Reduction Accord, under which the member states will, among other things, establish greenhouse gas reduction targets and develop a market-based and multi-sector cap-and-trade mechanism to help achieve such targets. In addition, on October 18, 2007, the KDHE denied an application by an unrelated utility for an air quality permit for two new proposed coal generators in Western Kansas in part because of concerns about the increase in CO₂ and emissions and the potential ill effects those plants might have on the environment and health. The KDHE noted that the decision constituted a first step in emerging policy to address existing and future CO₂ emissions in Kansas. The Midwest Greenhouse Gas Reduction Accord or other new or changed laws and regulations, as well as third party litigation that may be brought against us or our competitors, could result in requirements to install costly equipment, increase our operating expenses, reduce production from our plants or take other actions we are unable to identify at this time.

The degree to which we may 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 existing regulations, new regulations, legislation and the resolution of the NSR Investigation and the related DOJ lawsuit described above. Although we expect to recover in our rates most of 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 or the costs of any failure to comply with laws and regulations. Failure to recover these associated costs could have a material adverse effect on our consolidated financial statements.

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Accounting Regulations Unique to Public Utilities Could Change

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, 2008, we had recorded $829.2 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; (iii) a result of other regulatory actions that restrict cost recovery to a level insufficient to recover costs; or (iv) a change from current generally accepted accounting principles (GAAP) to another set of standards that does not recognize regulatory assets or liabilities, 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 statements.

Our Planned Capital Expenditures Are Significant To Our Results Of Operations

During the period from 2009 through 2011 and for the immediate years beyond, we plan to continue significant capital expenditures toward large projects including the expansion and modernization of our generation fleet and transmission network. Our anticipated capital expenditures for the period from 2009 through 2011, including costs of removal, are approximately $2.4 billion. Delays in engineering and construction times can occur throughout our industry. Because our capital expenditure program is large in comparison to our revenues and assets, cost increases or delays could materially affect our consolidated financial statements.

In addition, in order to fund our capital expenditure program, we rely to a large degree on access to our short-term credit facility and to long-term capital markets for debt and equity as sources of liquidity for capital requirements not satisfied by the cash flow from our operations. The secured and unsecured debt of Westar Energy and KGE are rated investment grade by all three of the best known rating agencies, but we cannot assure that such debt will continue to be rated investment grade. If the rating agencies were to downgrade Westar Energy’s or KGE’s secured or unsecured debt, our borrowing costs and the interest rates we pay on short-term and long-term debt would likely increase, possibly significantly. Further, market disruptions could increase our cost of borrowing or adversely affect our ability to access financial markets. Additional issuance of equity securities could dilute the value of our shares of our common stock and cause the market price of our common stock to fall. These factors could hinder our access to capital markets and limit or delay our ability to carry out our capital expenditure program.

Further, our recovery of capital expenditures depends in large degree on the outcome of retail and wholesale rate proceedings. Decisions made by the KCC or FERC, or delays in making such decisions, could have a material impact on our consolidated financial statements.

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Uncertainty in the Credit Markets and the Impact on the Economy in Our Service Territory

Continuing turmoil in the global credit markets, and the slowing of the global and U.S. economies, may have a number of effects on our operations, financial condition and capital expenditure program. While we cannot provide an exhaustive list of all possible effects, these market conditions may make capital more difficult and costly to obtain; may restrict liquidity available to us through our revolving credit facility; may reduce demand by our customers and increase delinquencies or non-payment by our customers; may adversely impact the financial condition of our suppliers, which may in turn limit our access to inventory or capital equipment; may reduce the credit available to our energy trading counterparties and correspondingly reduce our energy trading activity or increase our exposure to counterparty default; may require us to defer or limit elements of our capital expenditure program; may reduce the value of our financial assets and correspondingly adversely impact our earnings and net cash flow; may require us to provide additional funding to our nuclear decommissioning and pension trusts; and may increase the cost or decrease the availability of insurance to us or make insurance claims more difficult to collect. These and other related effects may have an adverse impact on our consolidated financial statements and in extreme circumstances, the combination of some or all of these effects might impact amounts available for the payment of dividends.

None.

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We own and have in service approximately 6,200 miles of transmission lines, approximately 23,800 miles of overhead distribution lines and approximately 4,100 miles of underground distribution lines.

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

Information on other legal proceedings is set forth in Notes 3, 13 and 15 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies –New Source Review Investigation” and “Legal Proceedings”, 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, 2003, and ended on December 31, 2008, 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 18, 2009, there were 23,822 common shareholders of record. For information regarding quarterly common stock price ranges for 2008 and 2007, see Note 20 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 2008 our board of directors declared four quarterly dividends, each at $0.29 per share, reflecting an annual dividend of $1.16 per share. On February 25, 2009, our board of directors declared a quarterly dividend of $0.30 per share on our common stock payable to shareholders on April 1, 2009. The indicated annual dividend rate is $1.20 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 2008. We provide further information on these restrictions in Note 17 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 2008, and our operating results for the years ended December 31, 2008, 2007 and 2006. 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, 2008:

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Decrease in Income from Operations

Income from operations decreased $52.7 million or 16% compared to last year. This decrease is attributable primarily to a decrease in energy marketing, cooler weather, reduced margins on power sold to a few large industrial customers and additional planned outages at our base load plants. Energy marketing decreased $22.5 million due primarily to the need to focus resources toward serving our retail customers during outages, changes in the relationships of prices among energy products historically traded and the continuing maturation of energy markets in which we participate reducing margin opportunities. A notable trend is that more transactions are being completed through RTO-sponsored markets as opposed to negotiated transactions directly between individual counterparties. In addition, as measured by cooling degree days, the weather during 2008 was 20% cooler than last year. While increases in the cost of fuel and purchased power generally are recoverable in the RECA applicable to our retail sales, we sold power to a few large industrial customers under contracts to which the RECA did not apply. Margins on sales to customers under these contracts were approximately $9.9 million lower compared to last year. Effective July 1, 2008, an industrial customer who accounted for approximately 65% of sales under these contracts is now served under a new tariff that incorporates the RECA. The remainder of these contracts will expire by the end of 2009. Furthermore, there were additional planned outages at our base load plants in 2008 that were longer in duration than the prior year. The additional planned outages required us to use more expensive fuel and to incur additional purchased power expense. This resulted in reduced margins on power sold, notwithstanding higher prevailing market prices. Margins on market-based wholesale sales decreased $9.1 million or 13% compared to last year.

Recognition of Previously Unrecognized Tax Benefits

In December 2007, we reached a tentative settlement with the IRS Office of Appeals on issues principally related to the method used to capitalize overheads to electric plant for years 1995 through 2002. This settlement, which was approved by the Joint Committee on Taxation and accepted by the IRS in February 2008, resulted in a 2008 net earnings benefit of approximately $39.4 million, including interest, due to the recognition of previously unrecognized tax benefits. The recognition of these previously unrecognized tax benefits resulted in earnings of $0.38 per share for the year ended December 31, 2008.

Changes in Rates

We filed an application with the KCC in May 2008 to increase retail rates by $177.6 million per year. The primary drivers for this application were investments in natural gas generation facilities, wind generation facilities and other capital projects, costs attributable to the 2007 ice storm, higher operating costs and an update of our capital structure. On October 27, 2008, all parties to the proceeding filed an agreement with the KCC supporting a $130.0 million annual increase in our retail rates. On January 21, 2009, the KCC issued an order approving the settlement agreement and the new retail rates became effective on February 3, 2009.

On July 1, 2008, we implemented an initial retail TDC on a revenue neutral basis to capture transmission costs ultimately approved in our 2005 general rate case. On September 18, 2008, the KCC granted our request to adjust the TDC to include more recent transmission costs approved by FERC and attributable to the retail portion of our transmission service. This served to increase our estimated annual retail revenues by $6.1 million.

On May 29, 2008, the KCC issued an order allowing us to increase our ECRR to include costs associated with investments made in 2007. This change went into effect on June 1, 2008, and served to increase our estimated annual retail revenues by $22.0 million.

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On December 2, 2008, FERC issued an order approving a settlement of our transmission formula rate that allows us to include our anticipated transmission capital expenditures for the current year in our transmission formula rate, subject to true up. In addition to the true up, we expect to update our transmission formula rate in January of each year to reflect changes in our projected operating costs and investments.

Increased Capacity and Future Plans

In May 2008, we and Electric Transmission America, LLC formed Prairie Wind Transmission, a joint venture company of which we own 50%. Prairie Wind Transmission is proposing to construct approximately 230 miles of 765 kV transmission facilities in Kansas extending west from near Wichita to near Dodge City and then south-southwest to the Kansas-Oklahoma border. On December 2, 2008, FERC approved a number of key rate components related to these transmission facilities and set aside for hearing the establishment of a formula rate and associated protocols. Should Prairie Wind Transmission receive the necessary regulatory approvals from the KCC and FERC, the facilities are expected to be in service by the end of 2013, contingent on a number of factors including the availability and cost of capital, not all of which are under our control. We will incur significant future capital expenditures related to this joint venture if Prairie Wind Transmission receives regulatory approval to build the transmission facilities.

We have been working with third parties to develop approximately 300 MW of wind generation facilities at three different sites in Kansas. Under the terms of the agreements, we will own approximately half of the wind generation facilities at an expected cost of approximately $282.0 million and will purchase energy produced by the wind generation facilities under twenty year supply contracts for the other half. One of the facilities from which we purchase energy began producing energy in December 2008 and we expect the other two to begin producing energy in early 2009.

We are constructing a 345 kV transmission line from our Gordon Evans Energy Center northwest of Wichita, Kansas, to a new substation near Hutchinson, Kansas, then on to our Summit substation near Salina, Kansas, a distance totaling approximately 100 miles. We completed construction of the first segment in December 2008 and expect the second segment to be completed by June 2010. We expect the total investment in the line and substations to be approximately $200.0 million.

In addition to the transmission line described above, we also plan to construct a new 345 kV line from a substation near Wichita to the Kansas-Oklahoma border, where we will interconnect with new facilities being built by an Oklahoma utility. The preliminary estimate of the investment in the line is approximately $90.0 million, which is subject to change pending final engineering design, labor and materials, among other factors. We expect to begin construction in 2010.

In 2008, we completed the first phase of our Emporia Energy Center, a new natural gas-fired peaking power plant consisting of seven combustion turbines located near Emporia in Lyon County, Kansas, comprising approximately 350 MW of capacity. We expect to complete construction of the second phase, consisting of two generating units that will add an additional approximately 320 MW of generating capacity, early in 2009 for a total investment of about $318.0 million.

Economic Conditions

In 2008, global economic growth slowed, liquidity was reduced in global capital markets and the U.S. entered a recession. The downturn became more intense in the fourth quarter of 2008. Growth in industrial production decreased from 2007 levels, and business and consumer confidence declined throughout 2008. The rate of inflation increased in the first half of 2008 with rising food and energy prices, but declined in the latter part of the year.

The state of the economy may adversely affect a number of aspects of our business. While the full impact of these events is currently unknown, several developments can be highlighted.

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Certain of our industrial and commercial customers have informed us that they are experiencing a decrease in orders and have reduced production and work schedules. Further, several of our large industrial customers have recently announced significant employee layoffs.

Our residential business may be affected by general economic conditions. The Kansas unemployment rate increased from 4.2% in December 2007 to 5.2% in December 2008. Initial unemployment claims in Kansas jumped to approximately 37,000 claims in December 2008 from approximately 18,000 claims in December 2007.

We cannot predict whether these developments will continue or when the economy generally may stabilize. We also cannot state whether or to what extent any such developments will impact our results of operations, which are affected by economic conditions as well as by a broad number of other factors, including without limitation those factors summarized in this Form 10-K in the sections entitled “Forward Looking Statements” and “Item 1A. Risk Factors.”

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 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 regulatory orders, 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 costs of approximately $22.7 million in 2008 and $21.4 million in both 2007 and 2006. These amounts reflect the pension costs of Westar Energy and our 47% responsibility for the pension costs of Wolf Creek. Pension costs for 2009 are expected to be approximately $38.1 million. The increase in pension costs from 2008 to that expected in 2009 is due primarily to significantly lower than expected investment returns in 2008. The investment gains or losses resulting from the difference between the expected return on assets and actual returns earned are deferred in the year the difference arises. The gain or loss recognition occurs by using a four-year moving average value of pension assets to measure the expected return on assets in the pension cost, and by amortizing deferred investment gains or losses over the average remaining service life of employees. See Notes 11 and 12 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans” and ‘Wolf Creek Employee Benefit Plans,” for additional discussion of Westar Energy and Wolf Creek benefit plans, respectively.

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 at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate the electric usage from the last meter read and record the corresponding unbilled revenue.

The accuracy of our unbilled revenue estimate is affected by factors including fluctuations in energy demands, weather, line losses and changes in the composition of customer classes. We had estimated unbilled revenue of $47.7 million as of December 31, 2008, and $43.7 million as of December 31, 2007.

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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 portfolio value as gains or losses in the period of change. With the exception of a fuel supply contract and a capacity sale contract, which we record as regulatory liabilities, 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. The prices we use to value these transactions reflect our best estimate of the fair value of these contracts. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial statements.

The tables below show the fair value of energy marketing contracts that were outstanding as of December 31, 2008, their sources and maturity periods.

The sources of the fair values of the financial instruments related to these contracts as of December 31, 2008, 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 as required by tax laws and regulatory practices.

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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.

We account for uncertainty in income taxes in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109.” The application of income tax law is complex. Laws and regulations in this area are voluminous and are often ambiguous. Accordingly, we must make subjective assumptions and judgments regarding income tax exposures. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our subjective assumptions and judgments can materially affect amounts we recognize in the consolidated financial statements. See Note 10 of the Notes to Consolidated Financial Statements, “Taxes,” for additional detail of our uncertainty in income taxes.

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 FIN 47, “Accounting for Conditional Asset Retirement Obligations.”

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

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 15 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 for the sale of such energy that have yet to settle.

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Market-based wholesale: Includes: (i) sales of energy to wholesale customers, the rates for which are generally based on prevailing market prices as allowed by FERC approved market-based tariffs, or where not permitted, pricing is based on incremental cost plus a permitted margin and (ii) changes in valuations for contracts for the sale of such 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; (iii) fees we earn for marketing services that we provide for third parties; and (iv) changes in valuations for contracts related to such transactions that have yet to settle.

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. 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. 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.

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2008 Compared to 2007

Below we discuss our operating results for the year ended December 31, 2008, compared to the results for the year ended December 31, 2007. Changes in results of operations are as follows.