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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

For the quarterly period ended September 30, 2005

OR

For the transition period from              to             

Commission File Number 1-7324

KANSAS GAS AND ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

777 West Central

Wichita, Kansas 67203

(316) 261-6611

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

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 is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 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.

Registrant meets the conditions of General Instruction H(1)(a) and (b) to Form 10-Q for certain wholly-owned subsidiaries and is therefore filing this Form with a reduced disclosure format.

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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:

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

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2004. 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, 2004. Any forward-looking statement speaks only as of the date such statement was made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

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PART I. Financial Information

ITEM 1. CONDENSED FINANCIAL STATEMENTS

KANSAS GAS AND ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)

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

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KANSAS GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

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

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KANSAS GAS AND ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands)

(Unaudited)

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

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KANSAS GAS AND ELECTRIC COMPANY

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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KANSAS GAS AND ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

Kansas Gas and Electric Company is a regulated electric utility incorporated in 1990 in Kansas. Unless the context otherwise indicates, all references in this quarterly report on Form 10-Q to “the company,” “KGE,” “we,” “us,” “our” and similar words are to Kansas Gas and Electric Company. We are a wholly owned subsidiary of Westar Energy, Inc. and we provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. We provide electric generation, transmission and distribution services to approximately 305,000 customers in south-central and southeastern Kansas, including the city of Wichita.

We own a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas, and a 47% interest in Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek.

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, 2004 (2004 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, valuation of our energy marketing portfolio, intangible assets, income taxes, our portion of WCNOC’s pension and other post-retirement benefits, our asset retirement obligations including 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 and nine months ended September 30, 2005 are not necessarily indicative of the results to be expected for the full year.

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New Accounting Pronouncement

Accounting for Conditional Asset Retirement Obligations: In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation” as used in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for the year ended December 31, 2005.

We currently have insulating materials at our power plants that contain asbestos. We have determined that the disposal of the asbestos represents a conditional asset retirement obligation that is within the scope of FIN 47. It is likely that we will record an asset retirement obligation pursuant to the requirements of FIN 47. We are currently in the process of determining the fair value of that disposal obligation. The amount of the retirement obligation will be recorded as of 1983, the date when the Occupational Safety and Health Administration published the Emergency Temporary Standard for asbestos. We will also capitalize the retirement obligation as an increase to the power plant’s carrying value. The amount of depreciation and accretion expense accruing since 1983 will be recorded as a regulatory asset.

Reclassifications

We have reclassified certain prior year amounts to conform with classifications used in the current-year presentation as necessary for a fair presentation of the financial statements.

3. RATE MATTERS AND REGULATION

Retail Rate Review

In accordance with a Kansas Corporation Commission (KCC) order, we filed an application with the KCC on May 2, 2005, to increase our retail electric rates and to adopt other practices under the KCC’s jurisdiction. We anticipate that any changes in our rates as a result of the rate review will become effective in January 2006. Key components of the application are as follows:

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On September 9, 2005, the KCC staff and intervenors in our rate case filed testimony with the KCC that proposes adjustments that would significantly decrease our electric rates. The KCC staff’s suggested adjustments would result in a decrease in our rates by approximately $59.4 million. On October 3, 2005, we filed with the KCC additional testimony to update our filing and rebut the KCC staff’s and intervenors’ findings, conclusions and proposed adjustments. The adoption of the KCC staff’s or intervenors’ proposed adjustments to our rates would have a material adverse effect on our financial condition and results of operations. The KCC is not bound by the recommendations of its staff or other intervenors. We anticipate a ruling by the KCC on or before December 28, 2005 but are unable to predict the outcome.

FERC Proceedings

Request for Change in Transmission Rates

On May 2, 2005, we filed an application with FERC to change our transmission rates. The application proposes a formula transmission rate that provides for annual adjustments to reflect changes in Westar Energy’s and our transmission costs. This is consistent with our proposal filed with the KCC on May 2, 2005 to separately charge retail customers for transmission service. We expect our proposed rates to become effective on December 1, 2005, subject to refund. We can provide no assurance that FERC will approve our application as filed.

Market-based Rates

On March 23, 2005, FERC instituted a proceeding concerning the reasonableness of Westar Energy’s and our market-based rates in our electrical control area and the electrical control areas of Midwest Energy, Inc. and Aquila, Inc.’s West Plains Energy division. On April 21, 2005, Westar Energy and we provided FERC with information it requested to complete its analysis. A FERC decision, expected by late 2005, could affect how we price future wholesale power sales to wholesale customers in our control area and to Midwest Energy and West Plains Energy and wholesale customers in their control areas. We do not expect the outcome of this matter to significantly impact our consolidated results of operations.

Service Reliability Standards

On February 10, 2004, the North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from an investigation of the August 14, 2003 blackout in portions of the northeastern United States. In February 2005, NERC approved reliability standards, which went into effect on April 1, 2005. We are in compliance with these standards and did not have to make any significant expenditures to be in compliance.

4. ACCOUNTS RECEIVABLE SALES PROGRAM

We sell our accounts receivable to WR Receivables Corporation, a wholly owned subsidiary of Westar Energy. WR Receivables has an agreement to sell up to $125.0 million of our qualified accounts receivable to a financial institution pursuant to an agreement entered into in 2000. The agreement has been extended annually since 2000 pursuant to mutual agreement of the parties. We renewed the agreement in July 2005 for one year on terms substantially similar to the expiring agreement.

The receivables sold by WR Receivables to the financial institution are not reflected in the accounts receivable balance in the accompanying consolidated balance sheets. The amounts sold to the financial institution were $105.0 million at September 30, 2005 and $80.0 million at December 31, 2004. We record this activity on the consolidated statements of cash flows in the “accounts receivable, net” line of cash flows from operating activities.

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We service, administer and collect the receivables on behalf of the financial institution. We paid administrative expenses to the financial institution of $1.2 million for the three months ended September 30, 2005 and $0.6 million for the same period of 2004 associated with the sale of these receivables, which represent the loss on the sale. We paid administrative expenses of $2.8 million for the nine months ended September 30, 2005 and $1.5 million for the same period of 2004. We include these expenses in other expense on our consolidated statements of income.

We record receivables transferred to WR Receivables at book value, net of allowance for bad debts. This approximates fair value due to the short-term nature of the receivable. We include the transferred accounts receivable in “accounts receivable, net,” on our consolidated balance sheets. The interests that we hold are presented in the table below.

5. INCOME TAXES AND TAXES OTHER THAN INCOME TAXES

We recorded income tax expense of approximately $10.3 million for the three months ended September 30, 2005 as compared to $12.3 million for the same period of 2004, and $14.2 million for the nine months ended September 30, 2005 as compared to $24.3 million for the same period of 2004.

We are a member of Westar Energy’s consolidated tax group. We file consolidated tax returns with Westar Energy. Westar Energy allocates to us our portion of consolidated income taxes based on our contribution to consolidated taxable income.

As of September 30, 2005 and December 31, 2004, we had recorded reserves for uncertain income tax positions of $3.5 million and $2.9 million, respectively. The tax positions may involve income, deductions or credits reported in prior year income tax returns that we believe were treated properly on such tax returns. The tax returns containing these tax reporting positions are currently under audit or will likely be audited by the Internal Revenue Service or other taxing authorities. The timing of the resolution of these audits is uncertain. If the positions taken on the tax returns are ultimately upheld or not challenged within the time available for such challenges, we will reverse these tax provisions to income. If the positions taken on the tax returns are determined to be inappropriate, we may be required to make cash payments for taxes and interest. The reserves are determined based on our best estimate of probable assessments by the applicable taxing authorities and are adjusted, from time to time, based on changing facts and circumstances.

As of September 30, 2005 and December 31, 2004, we also had a reserve of $1.2 million and $0.9 million, respectively, for probable assessments of taxes other than income taxes.

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6. COMMITMENTS AND CONTINGENCIES

Environmental Matters

Our activities are subject to environmental regulation by federal, state, and local governmental authorities. These regulations generally involve the use of water, discharges of effluents into the water, emissions into the air, the handling, storage and use of hazardous substances, and waste handling, remediation and disposal, among others. Congress or the State of Kansas may enact legislation, and the Environmental Protection Agency (EPA) or the State of Kansas may propose new regulations or change existing regulations, that could require us to reduce certain emissions at our plants.

Uncertain legislative and regulatory outcomes result in a wide range of potential expenditures. On August 9, 2005, Kansas City Power & Light Company (KCPL), the operator of our jointly owned La Cygne Generating Station (La Cygne), announced that it will begin preparations for the installation of environmental upgrades at La Cygne Unit No. 1. As work on these upgrades progresses, we will incur costs beginning in 2005 and continuing through the completion of installation in 2009. We anticipate that our share of these costs will be approximately $105.0 million. Additionally, we have identified the potential for up to $240.0 million of expenditures for other environmental projects over approximately 10 years. In addition to the capital investment, were we to install such equipment, we anticipate that we would incur a significant annual expense to operate and maintain the equipment and the operation of the equipment would reduce net production from our plants.

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

EPA New Source Review

Under Section 114(a) of the Clean Air Act (Section 114), the EPA is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to New Source Review requirements or New Source Performance Standards. These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could have reasonably been expected to result in a significant net increase in emissions. The Clean Air Act requires companies to obtain permits and, if necessary, install control equipment to remove emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

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

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

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Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC requires companies with nuclear power plants to prepare formal financial plans to fund nuclear decommissioning. We file a nuclear decommissioning and dismantlement study with the KCC every three years.

We filed an updated nuclear decommissioning and dismantlement cost estimate study with the KCC on September 1, 2005. Costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied upon the site-specific, technical information, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $243.3 million in 2005 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. We anticipate a KCC order on the September 2005 decommissioning study in the second quarter of 2006. The actual decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

7. ICE STORM

On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric service in a large portion of our service territory and damaged a significant portion of our electric distribution system. On March 22, 2005, we received an accounting authority order from the KCC that allows us to accumulate and defer for recovery the maintenance costs related to system restoration, as well as accumulate and record a carrying charge on the deferred balance. As of September 30, 2005, we have recorded $24.8 million as a regulatory asset related to these costs. Recovery of these costs is being considered as part of our rate review as discussed in Note 3, “Rate Matters and Regulation.”

8. RELATED PARTY TRANSACTIONS

Our cash management function, including cash receipts and disbursements, is performed by Westar Energy. An intercompany account is used to record receipts and disbursements between Westar Energy and us and between WR Receivables and us. The net amount payable to affiliates was approximately $152.0 million at September 30, 2005 and approximately $91.5 million at December 31, 2004 as reflected on our consolidated balance sheets.

Westar Energy provides all employees we use. Certain operating expenses have been allocated to us from Westar Energy. These expenses are allocated, depending on the nature of the expense, based on allocation studies, net investment, number of customers and/or other appropriate factors. We believe such allocation procedures are reasonable.

We declared and paid dividends to Westar Energy for the nine months ended September 30, 2005 of $20.0 million and $50.0 million for the same period of 2004.

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9. DEBT

The table below shows our long-term debt outstanding at September 30, 2005 and December 31, 2004.

On August 1, 2005, we repaid the outstanding $65.0 million aggregate principal amount of our 6.5% first mortgage bonds.

On May 6, 2005, Westar Energy amended its revolving credit facility dated March 12, 2004 to extend the term and reduce borrowing costs. The amended revolving credit facility matures on May 6, 2010. The facility allows Westar Energy to borrow up to an aggregate amount of $350.0 million, including letters of credit up to a maximum aggregate amount of $100.0 million. So long as there is no default or event of default under the revolving credit facility, Westar Energy may elect, subject to lender participation, to increase the aggregate amount of borrowings under this facility to $500.0 million. All borrowings under the revolving credit facility are secured by our first mortgage bonds.

10. LEGAL PROCEEDINGS

We are involved in various 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 results of operations.

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11. FERC SETTLEMENT

On May 19, 2005, Westar Energy and FERC reached a settlement regarding the matters related to the FERC investigation of power trades with Cleco Corporation and its affiliates, power transactions between Westar Energy’s system and its marketing operations and power trades in which Westar Energy or other trading companies acted as intermediaries. While these energy transactions do not apply to us, the FERC investigation included all transactions of both Westar Energy and us. The settlement does not require Westar Energy to make any monetary payments. As part of the settlement, Westar Energy and we will follow a three-year plan to ensure compliance with FERC rules. The settlement was neither a finding of wrongdoing by FERC nor an admission of wrongdoing by Westar Energy.

12. WCNOC INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

As a co-owner of WCNOC, we are indirectly responsible for 47% of the liabilities and expenses associated with the WCNOC pension and post-retirement plans. We accrue our 47% of the WCNOC cost of pension and post-retirement benefits during the years an employee provides service. The following table summarizes the net periodic costs for our 47% share of the WCNOC pension and post-retirement benefit plans.

13. LA CYGNE UNIT NO. 2 LEASE

On June 30, 2005, we and the owner of the La Cygne Unit No. 2 amended certain terms of the agreement relating to our lease of La Cygne Unit No. 2, including an extension of the lease term. The lease was entered into in 1987 with an initial term ending in September 2016. With the June 30, 2005 extension, the term of the lease will expire in September 2029. Upon expiration of the lease term in 2029, we have a fixed price option to purchase La Cygne Unit No. 2 for a price that is estimated to be the fair market value of the facility in 2029. We can also elect to renew the lease at the expiration of the lease term in 2029. However, any renewal period, when added to the initial lease term, cannot exceed 80% of La Cygne Unit No. 2’s estimated useful life.

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On June 30, 2005, we caused the owner of La Cygne Unit No. 2 to refinance the debt used by the owner to finance the purchase of the facility. At June 30, 2005, we had an unamortized gain, net of transaction costs, of $168.0 million as a result of the original transaction. This balance will be amortized over the term of the extended lease period. The savings resulting from extending the term of the lease and refinancing the debt will reduce our annual lease expense by approximately $11.0 million. These savings will be reflected in future utility rates.

The table below shows the estimated commitments for the La Cygne Unit No. 2 lease as reported in our 2004 Form 10-K as of December 31, 2004 and with the effect of the new lease as of September 30, 2005.

La Cygne Unit No. 2 Lease Commitments

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INTRODUCTION

We are a regulated electric utility in Kansas and a wholly owned subsidiary of Westar Energy. We provide rate-regulated electric service, together with the electric utility operations of Westar Energy, using the name Westar Energy. 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 since December 31, 2004, and our operating results for the three and nine months ended September 30, 2005 and 2004. 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

Overview

Several significant items have impacted us and our business operations since January 1, 2005, either directly or indirectly through Westar Energy.

Increasing Cost of Sales

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

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

Unit Availability: Our operating results are significantly influenced by the availability of our generating units. If our more economical units are not available, we must rely on more expensive sources of power to meet our load requirements. During the nine months ended September 30, 2005, due to various planned and unplanned unit outages as well as some coal conservation efforts, we produced approximately 865,000 less megawatt hours (MWh) than during the same period of 2004. The primary outages during the nine months ended September 30, 2005 were the scheduled refueling and maintenance outage at Wolf Creek and planned and unplanned outages at La Cygne Unit No. 1. The primary outages during the nine months ended September 30, 2004 were the planned and unplanned outages and reduced availability of Jeffrey Energy Center.

Operating Constraints: Our operating results are influenced by operating constraints on our generating units, such as coal conservation. If our more economical units are constrained, we must rely on more expensive sources of power to meet our load requirements and/or forego some opportunities in the wholesale power market. During the nine months ended September 30, 2005, coal conservation efforts, at times, reduced the energy generated at our more economical units and contributed to the decline in our market-based wholesale sales volumes. Coal conservation was initiated due to slower than expected coal deliveries as discussed below.

Coal Inventory and Delivery: Coal deliveries from the Powder River Basin region of Wyoming have been slower than expected due primarily to problems with the rail tracks used to deliver our coal and operational problems at the mines where the coal is obtained. Nearly all of the coal used in our coal-fired generating stations is from the Powder River Basin region of Wyoming. Longer rail delivery cycle times could have a material adverse effect on our financial condition and results of operations.

We have taken compensating measures based on current delivery cycle times, our assumptions about future delivery cycle times, fuel usage and planned inventory levels. These measures include, but are not limited to, reducing coal consumption during off-peak periods by revising normal operational dispatch of generating units, purchasing power or using more expensive power to serve customers, decreasing wholesale sales and ordering additional rail cars for delivery next year. Through September 30, 2005, these actions have helped reduce the financial impact resulting from slower delivery cycle times. The effect of the reduction in sales due to longer coal deliveries has been partially offset by higher prices in the power markets received for the power we have sold.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial conditions and results of operations are based on our condensed 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 2004 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 susceptibility of matters subject to change.

From December 31, 2004 through September 30, 2005, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2004 Form 10-K.

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OPERATING RESULTS

We evaluate operating results based on income from operations. We have various classifications of sales, defined as follows:

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

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

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

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

Energy marketing: Includes (1) financially settled products and physical transactions sourced outside our control area; and (2) changes in valuations for contracts that have yet to settle that may not be recorded either in cost of fuel or tariff- or market-based wholesale revenues.

Transmission: Reflects transmission revenues received, including those based on a tariff with the Southwest Power Pool (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, among other factors, rate regulation, customer conservation efforts, wholesale demand, the overall economy of our service area, the weather and competitive forces. Our wholesale sales are impacted by, among other factors, demand, cost of fuel and purchased power, price volatility, available generation capacity and transmission availability.

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Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Below we discuss our operating results for the three months ended September 30, 2005 as compared to the results for the three months ended September 30, 2004. Changes in results of operations are as follows:

The following table reflects changes in electric sales volumes, as measured by thousands of MWh of electricity. No sales volumes are shown for energy marketing, transmission, or other. Energy marketing activities are unrelated to electricity we generate.

Residential and commercial sales and sales volumes increased due primarily to warmer weather during the three months ended September 30, 2005 as compared to the same period of 2004. When measured by cooling degree days, the weather during the three months ended September 30, 2005 was 20% warmer than the same period last year and about the same as the 20-year average. We measure cooling degree days at a weather station we believe to be generally reflective of conditions in our service territory.

The warmer weather was also the primary reason tariff-based wholesale sales and sales volumes increased. We had more energy available from Jeffrey Energy Center, which also contributed to the increased tariff-based wholesale sales.

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Market-based wholesale sales increased due to higher market prices, which increased due largely to higher prevailing fuel prices. Market-based wholesale sales volumes declined because less energy was available for sale due to the increase in retail and tariff-based wholesale sales as well as coal conservation efforts.

Fuel expense increased due primarily to higher fuel prices, primarily natural gas. Fuel prices for the three months ended September 30, 2005 were approximately 31% higher than in the same period of 2004. We used approximately 3% more fuel to meet the increased demand reflected in our higher sales volumes. In addition, we used more expensive sources of generation because of the planned and unplanned outages and coal conservation at some of our more economical generating units.

The quantity of power purchased more than doubled due to higher customer demand, lower unit availability or operating constraints at some of our more economical generating units. Also affecting the increased purchased power expense were 17% higher average market prices. At times, it was more economical to purchase power than to operate our available generating units.

Operating and maintenance expense increased due primarily to a $3.5 million charge to write off plant operating system development costs at Wolf Creek due to non-performance of the vendor developing the system. Costs of operating and maintaining our distribution system increased $1.8 million due primarily to higher labor costs allocated to us and additional maintenance projects. These higher expenses were partially offset by a decline in expense related to the changes in the La Cygne Unit No. 2 operating lease as discussed in Note 13 of the Notes to Condensed Consolidated Financial Statements, “La Cygne Unit No. 2 Lease” and a decrease in maintenance expenses for our generating units.

Selling, general and administrative expense increased due primarily to the allocated portion of Westar Energy’s higher employee pension and benefit costs. Partially offsetting this increase were declines in insurance costs and general expenses.

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Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Below we discuss our operating results for the nine months ended September 30, 2005 as compared to the results for the nine months ended September 30, 2004. Changes in results of operations are as follows: