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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2009

OR

For the transition period from              to             

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

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

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Form 10-Q 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 and in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2008. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our operations and financial results may be included in our Annual Report on Form 10-K for the year ended December 31, 2008. 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. FINANCIAL INFORMATION

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q 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 681,000 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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our condensed consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America for interim financial information and in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with GAAP have been condensed or omitted. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008 (2008 Form 10-K).

Use of Management’s Estimates

When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, investments, valuation of our energy marketing portfolio, intangible assets, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and other post-retirement and post-employment benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months ended March 31, 2009, are not necessarily indicative of the results to be expected for the full year.

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Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit to other income (for equity funds) and interest expense (for borrowed funds) the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:

Earnings Per Share

Effective January 1, 2009, we adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” with retrospective application to prior periods. According to the provisions of this guidance, we have participating securities related to unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends as declared on an equal basis with common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS) in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings per Share.” This resulted in a decrease in basic EPS for the three months ended March 31, 2008, from $0.63 per share as previously reported in the first quarter 2008 Form 10-Q to $0.62 per share as reported in this Form 10-Q.

Under the two-class method, we reduce net income attributable to common stock by the amount of dividends declared in the current period. We allocate the remaining earnings to common stock and RSUs to the extent that each security may share in earnings as if all of the earnings for the period had been distributed. We determine the total earnings allocated to each security by adding together the amount allocated for dividends and the amount allocated for a participation feature. To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from the exercise of all outstanding stock options issued pursuant to the terms of our stock-based compensations plans. We compute the dilutive effect of shares issuable under our stock-based compensation plans using the treasury stock method.

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The following table reconciles our basic and diluted EPS from income from continuing operations.

Supplemental Cash Flow Information

New Accounting Pronouncements

We prepare our condensed consolidated financial statements in accordance with GAAP for the United States of America for interim financial information and in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. To address current issues in accounting, regulatory bodies have issued the following new accounting pronouncements that may affect our accounting or disclosure.

FSP No. FAS 157-4 – Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

In April 2009, FASB released FSP No. Financial Accounting Standard (FAS) 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” FSP No. FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for an asset or liability have significantly decreased. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP No. FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

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FSP No. FAS 115-2 and FAS 124-2 – Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, FASB released FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments,” which changes how other-than-temporary impairments of investments in debt securities are recognized and measured. This FSP also provides for changes in the presentation and disclosure requirements surrounding other-than-temporary impairments of investments in debt and equity securities. FSP No. FAS 115-2 and FAS 124-2 is effective for interim and annual reporting periods ending after June 15, 2009. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

FSP No. FAS 107-1 and APB 28-1 – Interim Disclosures about Fair Value of Financial Instruments

In April 2009, FASB released FSP No. FAS 107-1 and Accounting Principles Board (APB) Opinion 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” FSP No. FAS 107-1 and APB 28-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” to require disclosures about the fair value of financial instruments for interim reporting periods as well as in annual financial statements. This guidance is effective for interim and annual reporting periods ending after June 15, 2009. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

FSP No. FAS 132(R)-1 – Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, FASB released FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which requires enhanced disclosures about the plan assets of defined benefit pension and other postretirement benefit plans. These disclosures include how investment allocation decisions are made, the factors pertinent to understanding investment policies and strategies, the fair value of each major category of plan assets for pension plans and other postretirement benefit plans separately, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets and significant concentrations of risk within plan assets. FSP No. FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. We are currently evaluating what impact the adoption of this guidance will have on our consolidated financial statements.

FSP No. EITF 03-6-1 – Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, FASB released FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP No. EITF 03-6-1 provides that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. FSP No. EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008, with retrospective application to prior periods. We adopted this guidance effective January 1, 2009. See “—Earnings Per Share” above for additional information.

SFAS No. 161 – Disclosures about Derivative Instruments and Hedging Activities

In March 2008, FASB released SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – An Amendment of FASB Statement No. 133,” which requires expanded disclosure intended to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 amends and expands our disclosure requirements related to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” by requiring qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosure about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008. We adopted this guidance effective January 1, 2009. See Note 3, “Financial and Derivative Instruments, Energy Marketing and Risk Management,” for additional information.

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SFAS No. 157 – Fair Value Measurements

In September 2006, FASB released SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. In February 2008, FASB issued FSP No. FAS 157-2 which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The non-financial items subject to the deferral include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. We adopted SFAS No. 157 for financial assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. We adopted SFAS No. 157 for non-financial assets and liabilities recognized at fair value on a non-recurring basis effective January 1, 2009. The adoption of this guidance did not have a material impact on our consolidated financial statements. See Note 3, “Financial and Derivative Instruments, Energy Marketing and Risk Management,” for additional information.

3. FINANCIAL AND DERIVATIVE INSTRUMENTS, ENERGY MARKETING AND RISK MANAGEMENT

Recurring Fair Value Measurements

The following table provides the amounts and their corresponding level of hierarchy for our assets and liabilities that are measured at fair value.

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We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of March 31, 2009, we have recorded $1.7 million for our right to reclaim cash collateral and $0.7 million for our obligation to return cash collateral. As of December 31, 2008, we had recorded $5.1 million for our right to reclaim cash collateral and $4.5 million for our obligation to return cash collateral.

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three months ended March 31, 2009, and March 31, 2008.

A portion of the gains and losses contributing to changes in net assets in the above table is unrealized. The following table summarizes the unrealized gains and losses we recognized due to energy marketing activities during the three months ended March 31, 2009 and 2008, attributed to level 3 assets and liabilities still held as of March 31, 2009 and 2008, respectively.

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Derivative Instruments

We are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates that could affect our consolidated financial statements. We manage our exposure to these market risks through our regular operating and financing activities and, when appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments. We use the term economic hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on selected assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to offset the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We do not hold derivative instruments that are designated as hedging instruments as described in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

Energy Marketing Activities

We engage in both financial and physical trading to increase profits, manage our commodity price risk and enhance system reliability. Within our energy trading portfolio, we may establish certain positions to economically hedge a portion of physical sale or purchase contracts and we may enter certain positions attempting to take advantage of market trends and conditions. We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in market prices and take advantage of opportunities in the energy markets. We refer to this activity as energy marketing. As of March 31, 2009, our energy trading portfolio had exposure related to the following energy-related products.

Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have net open positions, we are exposed to the risk that changing market prices could have a material adverse impact on our consolidated financial statements.

To manage our exposure to commodity price changes, we use derivative contracts for non-trading purposes. We trade various types of fuel primarily to reduce exposure relative to the volatility of commodity prices. The wholesale power and fuel markets have been extremely volatile. This degree of volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service.

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers consume. Quantities of fossil fuel we use to generate electricity fluctuate from period to period based on availability, price and deliverability of a given fuel type as well as planned and unscheduled outages at our facilities that use fossil fuels and our nuclear plant refueling schedule. Our customers’ electricity usage could also vary from year to year based on weather, the economy or other factors.

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We classify derivative instruments that we use to manage commodity price risk inherent in fossil fuel and electricity purchases and sales as energy marketing contracts on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities. With the exception of certain fuel supply and electricity sale contracts, which we record as regulatory assets or regulatory liabilities, we include the change in the fair value of energy marketing contracts in sales on our consolidated statements of income.

The following table presents the fair value of derivative instruments related to our energy marketing reflected on our consolidated balance sheets.

Commodity Derivatives Not Designated as Hedging Instruments as of March 31, 2009

The following table presents how changes in market price resulting from the use of commodity derivative instruments affected our consolidated financial statements for the three months ended March 31, 2009.

In addition to commodity price risk, we are exposed to credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce our overall credit risk to an acceptable level.

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We have derivative instruments with commodity exchanges and other counterparties which do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of March 31, 2009, was $8.1 million, for which we had posted no collateral. If all credit-risk-related contingent features underlying these agreements had been triggered as of March 31, 2009, we would have been required to provide to our counterparties $5.8 million of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

4. RATE MATTERS AND REGULATION

KCC Proceedings

Changes in Prices

On January 21, 2009, the Kansas Corporation Commission (KCC) issued an order approving a $130.0 million annual increase in our retail prices. The new prices became effective on February 3, 2009.

On March 6, 2009, the KCC issued an order allowing us to adjust our transmission delivery charge (TDC) to include updated transmission costs that are attributable to the retail portion of our transmission service. This change went into effect on March 13, 2009, and will increase our estimated annual retail revenues by $31.8 million.

On March 17, 2009, we filed an application with the KCC to adjust our environmental cost recovery rider (ECRR) to include costs associated with environmental investments made in 2008. We expect that the KCC will issue an order on our request by May 31, 2009. We estimate that this will increase our annual retail revenues by $32.5 million.

5. TAXES

We recorded income tax expense of $4.4 million with an effective income tax rate of 28% from continuing operations for the three months ended March 31, 2009. We recorded an income tax benefit of $18.2 million with an effective income tax rate of negative 43% for the same period of 2008. The increase in the effective income tax rate for the three months ended March 31, 2009, is due primarily to the recognition of previously unrecognized tax benefits during the first quarter of 2008.

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

In January 2009, the Joint Committee on Taxation of the U.S. Congress approved our settlement with the IRS Office of Appeals regarding 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. The settlement involved a determination of the amount of the net capital loss and net operating loss carryforwards as of December 31, 2004, arising from the sale of Protection One. These loss carryforwards will be used to offset income in years after 2004. On March 31, 2009, we filed amended Federal income tax returns for years 2005, 2006, and 2007 to claim a portion of the tax benefits from the settlement. We expect to realize the remainder of the tax benefits from the settlement in future years. Under an agreement relating to the sale transaction, this settlement will result in our making a payment to Protection One in an amount equal to 50% of the net tax benefit (less certain adjustments) that we receive from the net operating loss carryforward arising from the sale. A non-cash net earnings benefit of approximately $33.0 million, net of the amount we have determined we owe Protection One under the aforementioned agreement, was recorded in discontinued operations in the first quarter of 2009 in recognition of this settlement.

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In April 2009, the IRS commenced examinations of our 2007 federal income tax return and the amended federal income tax returns we filed for prior years.

At December 31, 2008, our FASB Interpretation No. (FIN) 48 liability and unrecognized tax benefits were $39.0 million and $92.1 million, respectively. During the first quarter of 2009, the FIN 48 liability decreased from $39.0 million to $8.0 million (net of credit carryforwards of $24.0 million) and the amount of unrecognized tax benefits decreased from $92.1 million to $8.0 million (net of credit carryforwards of $24.0 million). The net decrease in FIN 48 liability and unrecognized tax benefits is primarily attributable to the recognition of $31.8 million of unrecognized tax benefits (net of credit carryforwards utilized on settlement of the FIN 48 liability) due to the completion of the IRS examination of years 2003 and 2004. We do not expect any other significant changes in the FIN 48 liability in the next 12 months. Included in the FIN 48 liability as of March 31, 2009, were $1.5 million (net of tax) of unrecognized tax benefits, which if recognized, would favorably impact our effective income tax rate.

At March 31, 2009, and December 31, 2008, we had $1.4 million and $3.8 million, respectively, accrued for interest on our liability related to unrecognized tax benefits. The decrease was attributable to the reduction in the FIN 48 liability. There were no penalties accrued at either March 31, 2009, or December 31, 2008.

As of March 31, 2009, and December 31, 2008, we maintained reserves of $3.8 million and $3.5 million, respectively, for probable assessments of taxes other than income taxes.

6. COMMITMENTS AND CONTINGENCIES

Environmental Projects

We will continue to make significant capital expenditures at our power plants for environmental air emissions projects. The amount 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 Environmental Protection Agency (EPA) lawsuit described below. In addition to the capital investment, in the event we install new equipment as a result of the EPA 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 prices of capital expenditures tied directly to environmental improvements, including those required by the Federal Clean Air Act. However, increased operating and maintenance costs can be recovered only through a change in our base rates following a rate review.

On February 28, 2008, we reached an agreement with the Kansas Department of Health and Environment (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 the costs to comply with these requirements may be material.

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EPA Lawsuit

Under Section 114(a) of the Federal Clean Air Act, 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.

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 Department of Justice (DOJ), on behalf of the EPA, 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 this 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. However, if a penalty is assessed against us, the penalty could be material and possibly may not be recovered in prices. We expect to incur substantial legal fees and expenses related to the defense of this lawsuit. We are not able to estimate the possible loss or range of loss at this time.

FERC Investigation

We are responding to a preliminary, non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008. On May 7, 2009, FERC staff advised us that it has preliminarily concluded that we have been improperly using secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleges we received $14.3 million of unjust profits through such activities. We do not agree with this amount and we continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are now beginning a review of transactions that FERC has identified and the preparation of a response. We are unable to predict the outcome of this investigation or its impact on our consolidated financial statements, but an adverse outcome could result in refunds and fines, the amounts of which could be material.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating 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, Inc. (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.

7. LEGAL PROCEEDINGS

In late 2002, two of our executive officers resigned or were placed on administrative leave from their positions. Our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment. As of March 31, 2009, we had accrued liabilities of $74.2 million for compensation not yet paid to them and $6.7 million for legal fees and expenses they have incurred. As of December 31, 2008, we had accrued liabilities of $74.9 million for compensation not yet paid to them and $6.8 million for legal fees and expenses they have incurred. The arbitration has been stayed pending final resolution of criminal charges filed by the United States Attorney’s Office against them in U.S. District Court in the District of Kansas. We intend to vigorously defend against the counterclaims they filed in the arbitration. We are unable to predict the ultimate impact of this matter on our consolidated financial statements.

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We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse effect on our consolidated financial statements.

See also Note 6, “Commitments and Contingencies.”

8. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

The following table summarizes the net periodic costs for our pension and post-retirement benefit plans.

In our 2008 Form 10-K, we indicated that we expected to contribute $51.9 million to the Westar Energy pension trust during 2009. As a result of recent guidance issued by the U.S. Department of the Treasury clarifying the assumptions underlying our pension plan, we now expect to contribute $33.6 million in 2009.

9. WOLF CREEK INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement plans. The following table summarizes the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans.

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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 the FERC.

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2009 and our operating results for the three months ended March 31, 2009 and 2008. As you read Management’s Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Decrease in Net Income

Net income decreased $17.0 million, or 28%, compared to last year. Settlements with the IRS occurring in the first quarters of both 2009 and 2008 accounted for $6.4 million of this decrease.

During the first quarter of 2008, we reached a settlement with the IRS for years 1995 through 2002 regarding issues principally related to the method used to capitalize overheads to electric plant. This settlement resulted in a first quarter 2008 net earnings benefit from continuing operations of approximately $39.4 million, including interest. This settlement also reduced our assessment of uncertain tax liabilities; therefore, we reversed $17.8 million of accrued interest related to uncertain tax liabilities in the first quarter of 2008.

In January 2009, we reached a settlement with the IRS for years 2003 and 2004 associated with the re-characterization of a portion of the loss we incurred on the sale of Protection One from a capital loss to an ordinary loss. This settlement resulted in a first quarter 2009 non-cash net earnings benefit from discontinued operations of approximately $33.0 million, or $0.30 per share, net of the amounts due to Protection One pursuant to the agreement related to the sale of Protection One.

Retail sales decreased 319,000 megawatt hours (MWh), or 7%, this quarter compared to the same period in 2008. As a result of prevailing economic conditions, certain of our industrial and commercial customers have reduced their demand for electricity. Additionally, because 2008 was a leap year, we had one day less of sales. Notwithstanding decreased retail MWh sales, retail revenues increased $22.6 million, or 8%, during the three months ended March 31, 2009, compared to the same period last year. This increase is due principally to our having increased our prices in accordance with regulatory authority.

Despite increased retail revenues and lower fuel and purchased power expense, net income decreased due principally to increases in our other operating expenses. Depreciation expense increased due primarily to the addition of generating plant, pollution control equipment, wind generation and transmission facilities in the past year. In addition, we experienced higher pension expense and increased maintenance costs at our power plants and for our distribution system.

Increases in Prices

On January 21, 2009, the KCC issued an order approving a $130.0 million annual increase in our retail prices. The new prices became effective on February 3, 2009.

On March 6, 2009, the KCC issued an order allowing us to adjust our TDC to include updated transmission costs that are attributable to the retail portion of our transmission service. This change went into effect on March 13, 2009, and will increase our estimated annual retail revenues by $31.8 million.

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Reduction in Planned Capital Expenditures

Due to the continued volatility in the capital markets and higher capital costs generally, we have reduced our anticipated capital expenditures for 2010 and 2011 by $366.8 million and $134.1 million, respectively, from what we reported in our 2008 Form 10-K. See “—Future Cash Requirements” below for additional information.

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 Condensed 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 in our 2008 Form 10-K 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.

From December 31, 2008 through March 31, 2009, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2008 Form 10-K.

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.

Wholesale: Sales of energy to electric cooperatives, municipalities and other electric utilities, the prices for which are generally either based on cost or based on prevailing market prices as prescribed by FERC authority. This category also includes changes in valuations of contracts for the sale of such energy that have yet to settle. Margins realized from these sales serve to lower our retail prices.

Energy marketing: Includes: (i) transactions based on market prices generally unrelated to the production of our generating assets; (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 of 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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Three Months Ended March 31, 2009, Compared to Three Months Ended March 31, 2008

Below we discuss our operating results for the three months ended March 31, 2009, compared to the results for the three months ended March 31, 2008. Changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.