(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 x No ¨

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

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 ~~as amended,~~ for the year ended December 31, ~~2003.~~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 ~~as amended,~~ for the year ended December 31, ~~2003.~~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.


	September 30, 2004			December 31, 2003			March 31, 2005			December 31, 2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38,328		$	79,559		$	25,804		$	24,611
Restricted cash		14,723			17,925			9,604			12,279
Accounts receivable, net		105,434			80,971			50,917			92,532
Inventories and supplies		127,143			136,636			118,841			124,563
Energy marketing contracts		14,689			35,385			21,583			23,155
Tax receivable								119,639			90,845
Deferred tax assets		33,361			119,041			9,869			7,218
Prepaid expenses and other		52,254			43,177
Assets of discontinued operations		—			570,541
Prepaid expenses								19,555			29,179
Other								41,090			11,558

Total Current Assets		385,932			1,083,235			416,902			415,940

PROPERTY, PLANT AND EQUIPMENT, NET		3,890,201			3,909,500			3,914,659			3,910,987

OTHER ASSETS:
Restricted cash		29,183			31,854			26,823			27,408
Regulatory assets		427,818			411,315			505,080			442,944
Nuclear decommissioning trust		84,123			80,075			90,312			91,095
Energy marketing contracts		7,644			4,190			11,619			4,904
Other		295,389			214,336			191,458			192,433

Total Other Assets		844,157			741,770			825,292			758,784

TOTAL ASSETS	$	5,120,290		$	5,734,505		$	5,156,853		$	5,085,711

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	70,986		$	190,747		$	165,000		$	65,000
Short-term debt		—			1,000
Accounts payable		101,666			94,700			110,301			105,593
Accrued taxes		109,472			102,287			120,024			97,874
Energy marketing contracts		16,764			28,000			21,266			20,431
Accrued interest								27,725			30,506
Other		134,182			128,384			121,212			99,170
Liabilities of discontinued operations		—			475,597

Total Current Liabilities		433,070			1,020,715			565,528			418,574

LONG-TERM LIABILITIES:
Long-term debt, net		1,659,383			1,966,039			1,528,511			1,639,901
Long-term debt, affiliate		—			103,093
Deferred income taxes and investment tax credits		1,033,630			1,039,620
Deferred income taxes								966,465			927,087
Unamortized investment tax credits								67,676			68,957
Deferred gain from sale-leaseback		141,938			150,810			136,024			138,981
Accrued employee benefits		97,968			101,892			119,354			120,152
Asset retirement obligation		85,512			80,695			88,852			87,118
Nuclear decommissioning		84,123			80,075			90,312			91,095
Energy marketing contracts		2,546			1,111			442			1,547
Other		250,226			153,695			183,714			182,977

Total Long-Term Liabilities		3,355,326			3,677,030			3,181,350			3,257,815

COMMITMENTS AND CONTINGENCIES (see Notes 7 and 8)
COMMITMENTS AND CONTINGENCIES (see Notes 7 and 10)
SHAREHOLDERS’ EQUITY:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares		21,436			21,436			21,436			21,436
Common stock, par value $5 per share; authorized 150,000,000 shares; issued 85,805,416 and 72,840,217 shares, respectively		429,027			364,201
Common stock, par value $5 per share; authorized 150,000,000 shares; issued 86,405,590 shares and 86,029,721 shares, respectively								432,028			430,149
Paid-in capital		913,273			776,754			916,773			912,932
Unearned compensation		(13,532	)		(15,879	)		(10,928	)		(10,361	)
Loans to officers		—			(2	)
Retained earnings (accumulated deficit)		(13,760	)		(102,782	)
Treasury stock, at cost, 203,575 shares		—			(2,391	)
Accumulated other comprehensive loss, net		(4,550	)		(4,577	)
Retained earnings								50,553			55,053
Accumulated other comprehensive income, net								113			113

Total Shareholders’ Equity		1,331,894			1,036,760			1,409,975			1,409,322

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,120,290		$	5,734,505		$	5,156,853		$	5,085,711

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


	Three Months Ended September 30,						Three Months Ended March 31,
	2004			2003			2005			2004
SALES	$	421,489		$	438,167		$	336,502		$	340,263

OPERATING EXPENSES:

Fuel and purchased power		120,037			121,434			91,797			101,762
Operating and maintenance		99,970			86,356			106,211			98,958
Depreciation and amortization		42,464			41,805			42,305			41,927
Selling, general and administrative		40,638			35,669			41,261			40,967

Total Operating Expenses		303,109			285,264			281,574			283,614

INCOME FROM OPERATIONS		118,380			152,903			54,928			56,649

OTHER INCOME (EXPENSE):
Investment earnings		5,194			6,394			2,224			3,030
Gain on sale of ONEOK, Inc. stock		—			38,522
Loss on extinguishment of debt and settlement of putable/callable notes		—			(17,588	)
Loss on extinguishment of debt								—			(154	)
Other income		681			331			676			677
Other expense		(4,404	)		(4,367	)		(4,807	)		(4,253	)

Total Other Income		1,471			23,292
Total Other Expense								(1,907	)		(700	)

Interest expense		31,508			57,495			29,864			43,425

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		88,343			118,700			23,157			12,524

Income tax expense		27,974			38,116			7,542			3,733

INCOME FROM CONTINUING OPERATIONS		60,369			80,584			15,615			8,791

Results of discontinued operations, net of tax		—			(161,651	)		—			6,888

NET INCOME (LOSS)		60,369			(81,067	)
Preferred dividends, net of gain on reacquired preferred stock		242			216
NET INCOME								15,615			15,679
Preferred dividends								242			242

EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK	$	60,127		$	(81,283	)
EARNINGS AVAILABLE FOR COMMON STOCK							$	15,373		$	15,437

BASIC AND DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):
Basic earnings available from continuing operations	$	0.70		$	1.11		$	0.18		$	0.12
Results of discontinued operations		—			(2.23	)
Results of discontinued operations, net of tax								—			0.09

Basic earnings (loss) available	$	0.70		$	(1.12	)
Basic earnings available							$	0.18		$	0.21

Diluted earnings available from continuing operations	$	0.69		$	1.09		$	0.18		$	0.12
Results of discontinued operations		—			(2.20	)
Results of discontinued operations, net of tax								—			0.09

Diluted earnings (loss) available	$	0.69		$	(1.11	)
Diluted earnings available							$	0.18		$	0.21

Average equivalent common shares outstanding		86,059,210			72,571,600			86,569,149			73,609,221

DIVIDENDS DECLARED PER COMMON SHARE	$	0.19		$	0.19		$	0.23		$	0.19

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

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

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


	Nine Months Ended September 30,
	2004			2003			Three Months Ended March 31,
				(As Restated)			2005			2004
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	90,027		$	71,042		$	15,615		$	15,679
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net of tax		(6,888	)		51,451			—			(6,888	)
Depreciation and amortization		126,649			125,435			42,305			41,927
Amortization of nuclear fuel		10,631			10,616			3,292			3,493
Amortization of deferred gain from sale-leaseback		(8,871	)		(8,871	)		(2,957	)		(2,957	)
Amortization of prepaid corporate-owned life insurance		9,770			9,467			4,872			4,451
Non-cash stock compensation		4,548			5,011			812			2,247
Net changes in energy marketing assets and liabilities		7,441			(6,169	)		(5,413	)		3,535
Loss on extinguishment of debt and settlement of putable/callable notes		18,840			26,425
Net changes in fair value of call option		—			2,178
Gain on sale of ONEOK, Inc. stock		—			(53,822	)
Gain on sale of utility plant and property		—			(12,294	)
Loss on extinguishment of debt								—			154
Accrued liability to certain former officers		7,184			904			470			5,579
Net deferred taxes		8,907			(65,976	)
Net deferred taxes and credits								37,269			(851	)
Changes in working capital items, net of acquisitions and dispositions:
Restricted cash		4,801			(1,592	)		3,265			(2,614	)
Accounts receivable, net		(24,463	)		(33,106	)		41,615			16,471
Inventories and supplies		9,493			4,746			5,721			7,459
Prepaid expenses and other		(42,141	)		13,833			26			1,398
Accounts payable		6,674			(4,173	)		4,585			(488	)
Accrued taxes								(6,644	)		23,214
Other current liabilities		(692	)		(69,640	)		(7,102	)		3,691
Accrued taxes		54,644			106,241
Changes in other, assets		5,917			9,154			(26,365	)		3,355
Changes in other, liabilities		(4,166	)		(15,979	)		(1,139	)		(4,074	)

Cash flows from operating activities		278,305			164,881			110,227			114,781

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(131,319	)		(112,968	)		(44,589	)		(44,544	)
Investment in corporate-owned life insurance		(19,658	)		(19,599	)
Removal, dismantlement and salvage of property, plant and equipment								(4,260	)		(2,278	)
Proceeds from sale of Protection One, Inc.		122,170			—			—			122,170
Proceeds from sale of ONEOK, Inc. stock		—			540,030
Proceeds from sale of plant and property		7,098			34,190			—			7,098
Repayment of officer loans		2			186			—			2
Proceeds from other investments		9,591			801

Cash flows (used in) from investing activities		(12,116	)		442,640			(48,849	)		82,448

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		(1,000	)		—			—			(1,000	)
Proceeds of long-term debt		623,301			—
Proceeds from long-term debt								246,616			—
Retirements of long-term debt		(1,191,808	)		(551,401	)		(290,998	)		(122,130	)
Funds in trust for debt repayments		78			5,079
Purchase of call option investment		—			(65,785	)
Net borrowings against cash surrender value of corporate-owned life insurance		55,138			57,072
Repayment of capital leases								(1,244	)		(1,238	)
Borrowings against cash surrender value of corporate-owned life insurance								873			939
Repayment of borrowings against cash surrender value of corporate-owned life insurance								(728	)		(74	)
Issuance of common stock, net		244,649			—			3,834			212,609
Cash dividends paid		(40,899	)		(45,033	)		(18,538	)		(12,748	)
Reissuance of treasury stock		1,927			5,165			—			1,927

Cash flows used in financing activities		(308,614	)		(594,903	)
Cash flows (used in) from financing activities								(60,185	)		78,285

Net cash from discontinued operations		1,194			39,747			—			197

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(41,231	)		52,365
NET INCREASE IN CASH AND CASH EQUIVALENTS								1,193			275,711

CASH AND CASH EQUIVALENTS:
Beginning of period		79,559			113,049			24,611			79,559

End of period	$	38,328		$	165,414		$	25,804		$	355,270

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
CASH PAID FOR:
Interest, net of amount capitalized	$	96,532		$	156,092
Income taxes		1,112			8,325
NON-CASH INVESTING AND FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and RSUs		10,328			5,994
Assets acquired through capital leases		2,733			1,180

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

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 ~~649,000~~655,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and ~~Hutchinson metropolitan areas.~~Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the ~~Wichita metropolitan area.~~city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy.

KGE owns 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.

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. The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and ~~the~~ notes included in our Annual Report on Form 10-K ~~as amended,~~ for the year ended December 31, ~~2003 (2003~~2004 (2004 Form ~~10-K, as amended)~~10-K).

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, income taxes, pension and other post-retirement and post-employment benefits, our asset retirement obligations including decommissioning of Wolf Creek, ~~net amount of tax benefits realizable from the disposition of our monitored security businesses,~~ 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, 2004~~March 31, 2005 are not necessarily indicative of the results to be expected for the full year.

For purposes of the pro forma disclosures required by Statement of Financial Accounting Standards (SFAS) No. 148, “Accounting for Stock Based Compensation - Transition and Disclosure,” the estimated fair value of stock options is amortized to expense over the relevant vesting period. Information related to the pro forma impact on our consolidated earnings (loss) and earnings (loss) per share follows:

Basic earnings ~~(loss)~~ per share applicable to equivalent common stock are based on the weighted average number of common shares outstanding and shares issuable in connection with vested restricted share units (RSUs) during the period reported. Diluted earnings ~~(loss)~~ per share include the effects of potential issuances of common shares resulting from the assumed vesting of all outstanding RSUs and the exercise of all outstanding stock options issued pursuant to the terms of our stock-based compensation plans and the additional issuance of shares under the employee stock purchase ~~plan.~~plan (ESPP). We discontinued the ESPP effective January 1, 2005. The dilutive effect of shares issuable under the ~~employee stock purchase plan,~~ESPP and our stock-based compensation ~~and stock options~~plans is computed using the treasury stock method.

The following table reconciles the weighted average number of equivalent common shares outstanding used to compute basic and diluted earnings ~~(loss)~~ per share.


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended March 31,
	2004	2003	2004	2003	2005	2004
DENOMINATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE:
Denominator for basic earnings (loss) per share – weighted average shares	86,059,210	72,571,600	81,849,084	72,299,260
DENOMINATOR FOR BASIC AND DILUTED EARNINGS PER SHARE:
Denominator for basic earnings per share — weighted average equivalent shares					86,569,149	73,609,221
Effect of dilutive securities:
Employee stock purchase plan shares	524	—	1,607	—	—	455
Employee stock options	2,313	1,041	2,167	—	1,710	2,080
Restricted share awards	814,803	819,426	771,285	727,721
Restricted share units					702,973	853,154

Denominator for diluted earnings (loss) per share – weighted average shares	86,876,850	73,392,067	82,624,143	73,026,981
Denominator for diluted earnings per share — weighted average shares					87,273,832	74,464,910

Potentially dilutive shares not included in the denominator since they are antidilutive	217,375	217,375	217,375	226,658	215,965	217,375

For purposes of the pro forma disclosures required by Statement of Financial Accounting Standards (SFAS) No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure,” the estimated fair value of stock options is amortized to expense over the relevant vesting period. Information related to the pro forma impact on our consolidated earnings and earnings per share follows:

Share-Based Payment:In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment: An Amendment of FASB Statements No. 123 and 95.” SFAS No. 123R requires companies to recognize as compensation expense the grant-date fair value of stock options and other equity-based compensation issued to employees. We will implement the provisions of the statement effective January 1, 2006.

We currently use RSUs for stock-based awards granted to employees. In addition, we have eliminated our employee stock purchase plan and all outstanding options have vested. Given the characteristics of our stock-based compensation program, we do not expect the adoption of SFAS No. 123R to materially impact our consolidated results of operations.

Accounting for Conditional Asset Retirement Obligations: In March 2005, 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 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 are currently evaluating what impact FIN 47 will likely have on our consolidated results of operations.

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.

Our previously filed consolidated statement of cash flows for the nine months ended September 30, 2003 presented cash flow activity related to our corporate-owned life insurance (COLI) policies net in the Operating Activities section of our consolidated statement of cash flows. For the nine months ended September 30, 2004, our consolidated statement of cash flows reports cash outflows associated with the portion of the premium payment that increases the cash surrender value of the COLI policies as an investing activity and the cash received from borrowings against the COLI policies as a financing activity. Accordingly, on our statement of cash flows for the nine months ended September 30, 2003, we have decreased cash flows from operating activities by $37.5 million, decreased cash flows from investing activities by $19.6 million as it relates to cash outflows associated with the portion of the premium payment that increases the cash surrender value of the COLI policies, and decreased cash flows used in financing activities by $57.1 million as it relates to the cash received from borrowings against the COLI policies.

After the issuance of the September 30, 2003 consolidated financial statements, we determined that certain components on our consolidated statement of cash flows for the nine months ended September 30, 2003 were incorrectly classified. As a result, the accompanying consolidated statement of cash flows for the nine months ended September 30, 2003 has been restated from the amounts previously reported to increase cash flows from operating activities by $14.7 million, to decrease cash flows from investing activities by $12.4 million and to decrease cash flows used in financing activities by $2.0 million.

3. RATE MATTERS AND REGULATION ~~— CURRENT STATUS OF THE DEBT REDUCTION PLAN~~

In ~~August 2003,~~accordance with a Kansas Corporation Commission (KCC) order, we ~~began ratably recording~~filed an application with the KCC on May 2, 2005, to propose an $84.1 million increase in our retail electric rates. We anticipate that our rates will change in January 2006. Key components of the filing are as follows:

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 our transmission costs. This is consistent with our proposal submitted to the KCC on May 2, 2005 to separately charge retail customers for transmission service. We expect the transmission rate to become effective no later than December 2005. We can provide no assurance that FERC will approve our application as filed.

InOn March 23, 2005, FERC instituted a proceeding concerning the ~~nine months ended September 30, 2004,~~reasonableness of our market-based rates in our electrical control area and the Midwest Energy, Inc. and West Plains Energy electrical control areas. On April 21, 2005, we ~~reduced,~~provided FERC with certain information it requested to complete its analysis. A FERC decision, expected by ~~$530.5 million~~mid-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. We do not expect the ~~debt shown on~~outcome of this matter to significantly impact our consolidated ~~balance sheet with internally generated cash,~~results of operations.

On February 10, 2004, the ~~proceeds received from the sale of Protection One, Inc. (Protection One) and proceeds~~North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from an ~~equity offering. Additionally, due~~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 have not had to ~~the sale of Protection One~~make any significant expenditures to be in ~~February 2004, we reduced the long-term debt that was included in the liabilities of discontinued operations by $305.2 million.~~compliance with these standards.

4. DISCONTINUED OPERATIONS — SALE OF PROTECTION ONE, ~~AND PROTECTION ONE EUROPE~~INC.

On February 17, 2004, we closed the sale of our interest in Protection One, Inc. to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). At closing, we received proceeds of $122.2 million. ~~The transaction did not include $26.6~~Pursuant to the terms of a November 12, 2004 settlement, Quadrangle paid us $32.5 million ~~par value of~~in cash as additional consideration, and we settled tax sharing-related obligations to Protection One by tendering $27.1 million in Protection One 7 3/³/8% senior notes, ~~due August 15, 2005, which we still hold as an available for sale security.~~

Protection One has been part of our consolidated tax group since 1997. During that time, under terms of a tax sharing agreement, we have reimbursed Protection One for current tax benefits attributable to Protection One usedincluding accrued interest, and paying $45.9 million in our consolidated tax return. Protection One is no longer a part of our consolidated tax group. We and Protection One did not formally terminate our tax sharing agreement and, based on discussions with Protection One and its counsel, there are several areas of potential dispute between us regarding our obligationscash. Our net cash payment under the ~~terms of the tax sharing agreement. The most material of these potential disputes involve (i) the proper treatment under the tax sharing~~settlement agreement of tax obligations or benefits arising out of the transaction in which we sold our interest in Protection One, including the impact of the cancellation of indebtedness income generated by the assignment of a credit agreement for less than the full amount outstanding under the credit agreement at closing on future payments, if any, to Protection One, (ii) whether any payments will be due to Protection One as a result of any tax benefits that may arise from a decision by us in the future to elect to treat the sale of our Protection One stock as a sale of assets under the Internal Revenue Code and (iii) whether payments due Protection One when we were subject to alternative minimum tax should have been calculated at the alternative minimum tax rate of 20% or the normal statutory rate of 35%. Because of these potential disputes, we have provided for these matters in our consolidated financial statements. We nevertheless believe that we have strong positions with respect to each of these items and will aggressively pursue our positions.

Before classifying our monitored services businesses as discontinued operations, we were unable to record a tax benefit for a significant portion of the goodwill impairment and amortization charges and losses of our monitored services businesses recorded in prior years. Upon classification as discontinued operations, GAAP required the current recognition of any tax benefit that will be realized in the foreseeable future, net of any required valuation allowance. We estimated the tax benefits associated with the capital loss on the sale of Protection One to be approximately $326.1was $13.4 million. Based on the sale of our ONEOK, Inc. (ONEOK) investment and current projections of taxable income, we estimate that it is likely that we will be able to realize approximately $93.9 million of these tax benefits. Therefore, we have recorded a $232.2 million valuation allowance for that portion of the tax benefit that we estimate may be unrealizable.

Results of discontinued operations for the three months ended March 31, 2004 are presented in the table ~~below:~~below.

~~The major classes of assets and liabilities of the monitored services businesses at December 31, 2003 were as follows:~~

~~On July 28, 2000, we entered into an agreement with~~ WR Receivables Corporation, a wholly owned ~~bankruptcy-remote special purpose entity (SPE),~~subsidiary, has an agreement with a financial institution whereby WR Receivables can sell an interest of up to ~~sell~~$125.0 million in a designated pool of our qualified accounts ~~receivable arising from the sale of electricity~~receivable. The agreement expires in July 2005 and, subject to the ~~SPE. These transfers~~mutual agreement of the parties, is renewable on an annual basis. We expect to renew the agreement on substantially similar terms.

The receivables sold by WR Receivables to the financial institution are accounted for as sales in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The SPE may sell up to $125 million of an undivided interestnot reflected in the accounts receivable balance in the accompanying consolidated balance sheets. The amounts sold to ~~a third-party conduit under various terms~~the financial institution were $95.0 million at March 31, 2005 and ~~conditions. The percentage ownership interest in receivables held by the third-party conduit will increase or decrease over time, depending~~$80.0 million at December 31, 2004. We record this activity on the ~~characteristics~~consolidated statements of cash flows in the “accounts receivable, net” line of cash flows from operating activities.

We service, administer and collect the receivables on behalf of the ~~SPE’s receivables, including delinquency rates and debtor concentrations. The agreement~~financial institution. Administrative expenses, which represent the loss on the sale, paid to the financial institution associated with the ~~third-party conduit is renewable annually upon agreement by all parties. On July 21, 2004,~~sale of these receivables were $0.7 million for the ~~agreement was extended through July 19,~~three months ended March 31, 2005 and $0.5 million for the same period of 2004. We include these expenses in other expense on ~~substantially similar terms.~~

~~The net SPE~~We record receivables ~~represent our retained interests in the~~ transferred ~~receivables and is recorded~~to WR Receivables at book value, net of ~~allowances~~allowance for bad debts. This approximates fair value due to the short-term nature of the receivable. ~~The SPE~~We include the transferred accounts receivable ~~is included~~ in accounts receivable, net, on our consolidated balance sheets. The interests that we hold are ~~included~~presented in the table ~~below:~~below.

The outstanding balance of SPE receivables is net of $90.0 million at September 30, 2004 and $80.0 million at December 31, 2003 in undivided ownership interests sold by the SPE to the third-party conduit.

The following table provides gross proceeds and repayments between the SPE and the third-party conduit. These amounts are provided for cash flow purposes and may not be reflective of accrual accounting. These items are recorded on the consolidated statements of cash flows in the accounts receivable, net, line of cash flows from operating activities.

We recorded income tax expense of approximately ~~$28.0~~$7.5 million for the three months ended ~~September 30, 2004~~March 31, 2005 as compared to ~~$38.1~~$3.7 million for the same period of ~~2003. We~~2004.

As of March 31, 2005 and December 31, 2004, we had recorded reserves for uncertain tax positions of $50.3 million and $49.7 million, respectively. Tax reserves are established for tax deductions or income positions taken in prior income tax ~~expense~~returns that we believe were treated properly on the tax returns but may be challenged if such tax returns are audited. The tax returns containing these tax reporting positions are currently under audit or will likely be audited. The timing of ~~approximately $37.6~~the resolution of these audits is uncertain. If the positions taken on the tax returns are ultimately sustained, we will reverse these tax provisions to income. If the positions taken on the tax returns are not ultimately sustained, 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 Internal Revenue Service or other taxing authorities and are adjusted, from time to time, based on changing facts and circumstances.

As of March 31, 2005 and December 31, 2004, we also had a tax reserve of $6.6 million, or $4.3 million after-tax, for probable assessments of taxes other than income taxes. During the ~~nine~~three months ended ~~September 30, 2004 as compared to $54.6 million~~March 31, 2005, we resolved certain state tax audit issues involving sales and property tax assessments by various state and local taxing authorities. These settlements resulted in the reversal of certain tax reserves for ~~the same period of 2003. Under the effective tax rate method, we compute the tax~~taxes other than income taxes, which was fully offset by additional accruals related to ~~year-to-date~~other probable assessments for taxes other than income except for significant, unusual or extraordinary items, at an estimated annual effective tax rate. We individually compute and recognize, when the transaction occurs, income tax expense related to significant, unusual or extraordinary items.taxes.

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 emissions. Such action could require us to install costly equipment, increase our operating expense and reduce production from our plants.

Uncertain legislative and regulatory outcomes result in a wide range of potential expenditures. Currently, we have identified the potential for up to $660 million of expenditures for environmental projects over approximately ten 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 New Source Review described below. Although we expect to recover such costs through our 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. If we were unable to recover these associated costs, we could have a material and adverse effect on our consolidated financial condition or results of operations.

The ~~United States Environmental Protection Agency (EPA)~~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 under Section 114(a) of the Clean Air Act (Section 114). 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 ~~has~~ requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at the three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements of the Clean Air Act.

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

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 March 31, 2005, we have recorded $29.7 million as a regulatory asset related to these costs. Recovery of these costs is to be considered as part of our rate review as discussed in Note 3, “Rate Matters and Regulation.”

On January 18, 2005, Westar Energy sold $250.0 million aggregate principal amount of Westar Energy first mortgage bonds, consisting of $125.0 million 5.15% bonds maturing in 2017 and $125.0 million 5.95% bonds maturing in 2035. On February 17, 2005, we used the net proceeds from the offering, together with cash on hand, additional funds raised through the accounts receivable conduit facility and borrowings under Westar Energy’s revolving credit facility, to redeem the remaining $260.0 million aggregate principal amount of Westar Energy 9.75% senior notes due 2007. Together with accrued interest and a premium equal to approximately 12% of the outstanding senior notes, we paid $298.5 million to redeem the Westar Energy 9.75% senior notes due 2007. All borrowings under Westar Energy’s revolving credit facility used for the redemption of the 9.75% senior notes were repaid prior to March 31, 2005.

On May 6, 2005, Westar Energy amended and restated its revolving credit facility dated March 12, 2004 to extend the term and reduce borrowing costs. The amended and restated revolving credit facility matures on May 6, 2010. The facility allows us to borrow up to an aggregate 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 to increase the aggregate amount of borrowings under this facility to $500 million by increasing the commitment of one or more lenders who have agreed to such increase, or by adding one or more new lenders with the consent of the Administrative Agent and letter of credit issuing bank, which will not be unreasonably withheld. All borrowings under the revolving credit facility are secured by KGE first mortgage bonds.

We and certain of our present and former officers and directors are defendants in a consolidated purported class action lawsuit in United States District Court in Topeka, Kansas, “In Re Westar Energy, Inc. Securities Litigation,” Master File No. 5:03-CV-4003 and related cases. Plaintiffs filed a Consolidated Amended Complaint on July 15, 2003. In early April 2005, we reached an agreement in principle with the plaintiffs to settle this lawsuit for $30.0 million. We will pay $1.25 million of the settlement and our insurance carriers will pay $28.75 million of the settlement, which includes the payments by our insurance carrier related to the settlement of the shareholder derivative lawsuit described below, less legal fees for the plaintiffs’ counsel in that matter. The settlement is subject to the execution of definitive documents and approval by the court. These financial statements reflect this settlement. The lawsuit is brought on behalf of purchasers of our common stock between March 29, 2000, the date we announced our intention to separate our electric utility operations from our unregulated businesses, and November 8, 2002, the date the KCC issued an order prohibiting the separation. The lawsuit alleges that we violated federal securities laws by making material misrepresentations or omitting material facts concerning the purpose and benefits of the previously proposed separation of our electric utility operations from our unregulated businesses, the compensation of our senior management and the independence and functioning of our board of directors and that as a result we artificially inflated the price of our common stock. On August 26, 2004, the court issued an order granting a joint motion of all parties, which stayed the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The court also denied without prejudice motions to dismiss the lawsuit filed by us and other defendants. The court stated its intention to set aside the order upon notice by any party that mediation efforts were unsuccessful, in which case the court would address the motions to dismiss the lawsuit. We intend to vigorously defend against this action. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

We and certain of our present and former officers and employees are defendants in a consolidated purported class action lawsuit filed in United States District Court in Topeka, Kansas, “In Re Westar Energy ERISA Litigation, Master File No. 03-4032-JAR.” Plaintiffs filed a Consolidated Amended complaint on October 20, 2003. The lawsuit is brought on behalf of participants in, and beneficiaries of, our Employees’ 401(k) Savings Plan between July 1, 1998 and January 1, 2003. The lawsuit alleges violations of the Employee Retirement Income Security Act arising from the conduct of certain present and former officers and employees who served or are serving as fiduciaries for the plan. The conduct is related to alleged securities law violations related to the previously proposed separation of our electric utility operations from our unregulated businesses, our rate cases filed with the KCC in 2000, the compensation of and benefits provided to our senior management, energy marketing transactions with Cleco Corporation ~~(Cleco)~~ and the first and second quarter 2002 restatements of our consolidated financial statements related to the revised goodwill impairment charge and the mark-to-market charge on our putable/callable notes. On August 26, 2004, the court issued an order granting a joint motion of all parties ~~which stayed~~requesting a stay of the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The court also denied without prejudice motions to dismiss the lawsuit filed by us and other defendants. The court stated its intention to set aside the order upon notice by any party that mediation efforts were unsuccessful, in which case the court would address the motions to dismiss the lawsuit. On February 8, 2005, the court held a conference at which the parties notified the court that efforts to settle the lawsuit through mediation had not been successful. The court then issued an order renewing the previously filed motions to dismiss and issued a scheduling order addressing the scope and timing of discovery in the lawsuit. We intend to vigorously defend against this action. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

Certain present and former members of our board of directors and officers are defendants in a shareholder derivative complaint filed April 18, 2003, “Mark Epstein vs David C. Wittig, Douglas T. Lake, Charles Q. Chandler IV, Frank J. Becker, Gene A. Budig, John C. Nettels, Jr., Roy A. Edwards, John C. Dicus, Carl M. Koupal, Jr., Larry D. Irick and Cleco Corporation, defendants, and Westar Energy, Inc., nominal defendant, Case No. 03-4081-JAR.” Plaintiffs filed an amended shareholder derivative complaint on July 30, 2003. In early April 2005, a special litigation committee of our board of directors approved an agreement in principle to settle this lawsuit for $12.5 million to be paid to us by our insurance carriers. This recovery, less estimated attorney’s fees of $2.5 million, will be used to fund a portion of the $30.0 million settlement of the securities class action lawsuit as described above. The settlement is subject to the execution of definitive documents and approval by the court. Among other things, the lawsuit claims that the defendants (i) breached fiduciary duties owed to us because of the actions and omissions described in the report of the special committee of our board of directors, (ii) caused or permitted our assets to be wasted on perquisites for certain insiders and (iii) caused or permitted our May 6, 2002 proxy statement to be issued with materially false and misleading statements. ~~The plaintiffs seek unspecified monetary damages and other equitable~~

relief. In October 2003, our board of directors appointed a special litigation committee of the board to evaluate the amended shareholder derivative complaint. The members of the committee were Mollie Hale Carter, Arthur B. Krause and Michael F. Morrissey. On August 26, 2004, the court issued an order granting a joint motion of all parties, which stayed the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. Plaintiffs have informed us they intend to file a motion seeking leave to amend the amended consolidated complaint if the mediation efforts are unsuccessful. The court would then set a date for us, and other defendants who have not already filed a response to the complaint, to respond to the amended complaint. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

On June 13, 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against David C. Wittig, our former president, chief executive officer and chairman, and Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, arising out of their previous employment with us. Mr. Wittig and Mr. Lake have filed counterclaims against us in the arbitration alleging substantial damages related to the termination of their employment and the publication of the report of the special committee of our board of directors. We intend to vigorously defend against these claims. The arbitration has been stayed pending the completion of a trial for Mr. Wittig and Mr. Lake on criminal charges in U.S. District Court in the District of Kansas. We are unable to predict the ultimate impact of this matter on our consolidated financial position, results of operations and cash flows.

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 position or results of operations.

See also Note ~~7 for discussion~~11, “Ongoing Investigations – Department of ~~alleged violations of the Clean Air Act~~Labor Investigation” and Note 12, “Potential Liabilities to David C. Wittig and Douglas T. Lake” for additional discussion of ~~potential liabilities to Mr. Wittig and Mr. Lake.~~other legal matters.

~~9. COMMON STOCK ISSUANCE~~11. ONGOING INVESTIGATIONS – Department of Labor Investigation

On ~~March 31, 2004,~~February 1, 2005, we ~~sold, through an underwritten public offering, 10.5 million shares~~received a subpoena from the Department of Labor seeking documents related to our ~~common stock at $20.65 per share. On April 2, 2004,~~Employees’ 401(k) Savings Plan and our defined pension benefit plan. At this time, we ~~sold approximately 1.6 million additional shares at~~do not know the ~~same price as a result~~specific purpose of the ~~underwriters exercising their over-allotment option~~investigation, and we are unable to predict the ultimate outcome of the investigation or its impact on ~~March 31, 2004. We received net cash proceeds~~us. See Note 10, “Legal Proceedings,” for discussion of ~~$239.9 million from these issuances.~~

~~During the nine months ended September 30, 2004, we made the following changes~~a class action lawsuit brought on behalf of participants in our ~~long-term debt:~~

During the nine months ended September 30, 2004, we recognized a loss of $16.1 million in connection with the redemption of some of our senior unsecured notes and $2.7 million in connection with the redemption of the Western Resources Capital I 7 7/8% Cumulative Quarterly Income Preferred Securities, Series A.

On March 12, 2004, we entered into a new revolving credit facility. The credit facility matures on March 12, 2007 and will be used as a source of short-term liquidity. It allows us borrowings up to an aggregate limit of $300.0 million, including letters of credit up to a maximum aggregate amount of $50.0 million. At September 30, 2004, we had no outstanding borrowings and $10.7 million of letters of credit outstanding under the revolving credit facility. All borrowings under the revolving credit facility are secured by KGE first mortgage bonds.Employee’s 401(k) Savings Plan.

During the ~~nine~~three months ended ~~September 30, 2004,~~March 31, 2005, we increased the amount of our accrued liability for potential obligations to Mr. Wittig and Mr. Lake by ~~$9.0~~$0.5 million to ~~$60.5~~$58.3 million from ~~$51.5~~$57.8 million at December 31, ~~2003.~~2004. The increase in the amount of the liability included $4.8 million as a result of the satisfaction of vesting requirements for RSUs previously granted to Mr. Wittig and Mr. Lake and the expenses associated with the redemption by the issuer of the securities underlying these RSUs, $1.6 million for dividends on RSUs and other shares, and approximately $0.8 millionwas for potential benefits due under an executive salary continuation ~~plan.~~plan and RSUs. In addition, we have accrued ~~$1.8~~$2.7 million for ~~actual and estimated~~ legal fees and expenses incurred by Mr. Wittig and Mr. Lake. As discussed above in Note 8,10, “Legal Proceedings,” we have filed a demand for arbitration with the American Arbitration Association seeking to avoid payment of compensation and other benefits Mr. Wittig and Mr. Lake claim to be owed to them, including ~~the~~ RSUs and other compensation and benefits, ~~described above,~~ as a result of their prior employment with us.

We will likely incur substantial additional expenses for legal fees and expenses incurred by Mr. Wittig and Mr. Lake related to the arbitration proceeding discussed above, the defense of the criminal charges filed by the United States Attorney’s Office in Topeka, Kansas, against Mr. Wittig and Mr. Lake, and the legal proceedings described in Note 810, “Legal Proceedings,” above. We are unable to estimate the amount of the additional legal fees and expenses that will be incurred by Mr. Wittig and Mr. Lake for which we may be ultimately responsible. ~~We are also currently unable to determine the amount of the fees which may be recovered under any applicable directors and officers liability insurance policies.~~

As we reported in our 2003 Form 10-K, as amended, ONEOK notified us of its decision to terminate portions of the shared services agreement we had with them. Major items that were terminated in September 2004 included electric service orders, call center functions, bill processing and remittance processing. In addition to joint meter reading, we plan to continue to share some facilities and a mobile communications system.

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

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 ~~plans.~~

~~We previously disclosed in our 2003 Form 10-K, as amended, that we expected to contribute $20.0 million in 2004 to our~~cost of pension and post-retirement ~~benefit plan. As of September 30, 2004, $13.3 million of~~benefits during the ~~contribution has been made. We anticipate contributing~~years an ~~additional $4.4 million to fund our post-retirement benefit plan in 2004 for a total of $17.7 million.~~

~~In December 2003, the United States Congress passed and the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act).~~employee provides service. The Medicare Act introduced a prescription drug benefit under Medicare as well as a federal subsidy beginning in 2006. This subsidy will be paid to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. We believe our retiree health care benefits plan is at least actuarially equivalent to Medicare and is eligible for the federal subsidy. We elected to defer the recognition of the effects of the Medicare Act on our consolidated financial statements until final authoritative guidance on the subsidy was issued by the Financial Accounting Standards Board (FASB). The final guidance under FASB Staff Position Financing Accounting Standards (FAS) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” was issued on May 19, 2004. We adopted the guidance in the third quarter of 2004. Treating the future subsidy under the Medicare Act as an actuarial experience gain, as required by the guidance, decreased the accumulated post-retirement benefit obligation by approximately $3.8 million. The subsidy also decreasedfollowing table summarizes the net periodic ~~post-retirement benefit cost by approximately $0.3 million~~costs for ~~the three and nine months ended September 30, 2004.~~

~~Prior to 2004 we had identified two reportable segments: “Electric Utility” and “Other.” Our “Electric Utility” segment consisted of~~ our integrated electric utility operations. “Other” included our former ownership interests in ONEOK, Protection One and Protection One Europe and other investments that in the aggregate were immaterial to our business or consolidated results of continuing operations.

With the sale of our interests in ONEOK, Protection One Europe and Protection One, we are now a vertically integrated electric utility with a single operating segment. Our chief operating decision maker evaluates our financial performance based on earnings (loss) per47% share of the ~~entire company. We no longer have a distinction between segments for utility operations~~WCNOC pension and ~~other investments.~~post-retirement benefit plans.

The table below provides the segment information previously provided for the interim reporting periods ended September 30, 2003. Comparable information for the three and nine months ended September 30, 2004 can be found on the accompanying consolidated statements of income.

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail in Kansas ~~under the regulation of the KCC~~ and at wholesale in a multi-state region in the central United States under the regulation of the ~~Federal Energy Regulatory Commission (FERC).~~KCC and FERC.

~~Our goals are to improve~~The following management’s discussion and analysis reflects several significant events that affected our core utility business by improving customer service, expanding our wholesale sales, improving our credit quality, improving our relationships with regulators, shareholders, employees and other interested parties and restoring our dividend to a payout level that we believe to be consistent with similarly situated regulated electric utility companies.

Inconsolidated results of operations over the ~~nine~~course of the three months ended September 30, 2004, we reduced by $530.5 million, the debt shown on our consolidated balance sheet with internally generated cash, the proceeds received from the sale of Protection One and proceeds fromMarch 31, 2005. We experienced an ~~equity offering. Additionally, due to the sale of Protection One~~ice storm in ~~February 2004, we reduced the long-term debt that was included in the liabilities of discontinued operations by $305.2 million.~~

~~Key factors affecting our business in any given period include the weather, the economic well-being of~~ our service territory ~~performance~~in January 2005 causing us to incur approximately $40.0 million in costs to restore our system. As of ~~our physical plant, conditions~~March 31, 2005, we have recorded $29.7 million as a regulatory asset related to the associated maintenance costs. Also in January 2005, we redeemed $260.0 million of 9.75% debt due in 2007 and issued $125.0 million of 5.15% Westar Energy first mortgage bonds due in 2017 and $125.0 million of 5.95% Westar Energy first mortgage bonds due in 2035. In March, we recorded a non-cash $12.3 million mark-to-market gain on fuel supply contracts that more than offset higher fuel costs incurred during the ~~markets for fuel and wholesale electricity, impacts of regulation and the effects of public policy initiatives. For additional risk factors affecting our business, see our 2003 Form 10-K, as amended.~~three months ended March 31, 2005.

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.

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 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 ~~2003~~2004 Form 10-K ~~as amended,~~ 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.

~~Since~~From December 31, ~~2003,~~2004 through March 31, 2005, we have not experienced any significant changes in our critical accounting estimates. For additional information, ~~on our critical accounting estimates,~~ see our ~~2003~~2004 Form ~~10-K, as amended.~~10-K.

We evaluate operating results based on basic earnings ~~(loss)~~ per share. We have various classifications of sales, defined as follows:

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

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

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

~~Market-based wholesale:~~ Includes sales of electricity to other wholesale customers, the rate for which is based on prevailing market rates as allowed by our FERC approved market-based tariff, and changes in valuations of contracts that have yet to settle.

~~Energy marketing:~~ Includes: (1) market-based energy transactions unrelated to our generation or the needs of our regulated customers; (2) financially settled products and physical transactions sourced outside our control area; and (3) 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.

~~Network integration:~~ ~~Reflects a network transmission tariff with the Southwest Power Pool (SPP) as described in more detail in our 2003 Form 10-K, as amended.~~

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 and available generation capacity. ~~For additional risk factors affecting our business, see our 2003 Form 10-K, as amended.~~

Three Months Ended ~~September 30, 2004~~March 31, 2005 Compared to Three Months Ended ~~September 30, 2003:~~March 31, 2004: Below we discuss our operating results for the three months ended ~~September 30, 2004~~March 31, 2005 as compared to the results for the three months ended ~~September 30, 2003.~~March 31, 2004. Changes in results of operations are as follows:


	Three Months Ended September 30,											Three Months Ended March 31,
	2004			2003			Change			% Change		2005			2004			Change			% Change
	(In Thousands, Except Per Share Amounts)											(In Thousands, Except Per Share Amounts)
SALES:
Residential	$	144,296		$	160,691		$	(16,395	)	(10.2	)	$	93,682		$	94,445		$	(763	)	(0.8	)
Commercial		116,996			117,743			(747	)	(0.6	)		84,960			83,694			1,266		1.5
Industrial		62,920			64,092			(1,172	)	(1.8	)		55,767			56,719			(952	)	(1.7	)
Other retail		277			(56	)		333		594.6			188			(39	)		227		582.1

Total Retail Sales		324,489			342,470			(17,981	)	(5.3	)		234,597			234,819			(222	)	(0.1	)
Tariff-based wholesale		44,140			46,095			(1,955	)	(4.2	)		35,965			32,516			3,449		10.6
Market-based wholesale		22,464			15,482			6,982		45.1			41,722			41,178			544		1.3
Energy marketing		4,922			9,501			(4,579	)	(48.2	)		(95	)		6,487			(6,582	)	(101.5	)
Network integration (a)		15,640			14,959			681		4.6
Transmission (a)													19,559			19,665			(106	)	(0.5	)
Other		9,834			9,660			174		1.8			4,754			5,598			(844	)	(15.1	)

Total Sales		421,489			438,167			(16,678	)	(3.8	)		336,502			340,263			(3,761	)	(1.1	)

OPERATING EXPENSES:
Fuel used for generation ~~(b)~~		97,481			103,448			(5,967	)	(5.8	)		80,053			85,478			(5,425	)	(6.3	)
Purchased power		22,556			17,986			4,570		25.4			11,744			16,284			(4,540	)	(27.9	)
Operating and maintenance		99,970			86,356			13,614		15.8			106,211			98,958			7,253		7.3
Depreciation and amortization		42,464			41,805			659		1.6			42,305			41,927			378		0.9
Selling, general and administrative		40,638			35,669			4,969		13.9			41,261			40,967			294		0.7

Total Operating Expenses		303,109			285,264			17,845		6.3			281,574			283,614			(2,040	)	(0.7	)

INCOME FROM OPERATIONS		118,380			152,903			(34,523	)	(22.6	)		54,928			56,649			(1,721	)	(3.0	)

OTHER INCOME (EXPENSE):
Investment earnings		5,194			2,438			2,756		113.0			2,224			3,030			(806	)	(26.6	)
ONEOK dividends		—			3,956			(3,956	)	—
Gain on sale of ONEOK stock		—			38,522			(38,522	)	—
Loss on extinguishment of debt and settlement of putable/callable notes		—			(17,588	)		17,588		—
Loss on extinguishment of debt													—			(154	)		154		100.0
Other income		681			331			350		105.7			676			677			(1	)	(0.1	)
Other expense		(4,404	)		(4,367	)		(37	)	(0.8	)		(4,807	)		(4,253	)		(554	)	(13.0	)

Total Other Income		1,471			23,292			(21,821	)	(93.7	)
Total Other Expense													(1,907	)		(700	)		(1,207	)	(172.4	)

Interest expense		31,508			57,495			(25,987	)	(45.2	)		29,864			43,425			(13,561	)	(31.2	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		88,343			118,700			(30,357	)	(25.6	)		23,157			12,524			10,633		84.9
Income tax expense		27,974			38,116			(10,142	)	(26.6	)		7,542			3,733			3,809		102.0

INCOME FROM CONTINUING OPERATIONS		60,369			80,584			(20,215	)	(25.1	)		15,615			8,791			6,824		77.6
Results of discontinued operations, net of tax		—			(161,651	)		161,651		—			—			6,888			(6,888	)	(100.0	)

NET INCOME (LOSS)		60,369			(81,067	)		141,436		174.5
Preferred dividends, net of gain on reacquired preferred stock		242			216			26		12.0
NET INCOME													15,615			15,679			(64	)	(0.4	)
Preferred dividends													242			242			—		—

EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK	$	60,127		$	(81,283	)	$	141,410		174.0
EARNINGS AVAILABLE FOR COMMON STOCK												$	15,373		$	15,437		$	(64	)	(0.4	)

BASIC EARNINGS (LOSS) PER SHARE	$	0.70		$	(1.12	)	$	1.82		162.5
BASIC EARNINGS PER SHARE												$	0.18		$	0.21		$	(0.03	)	(14.3	)

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


	Three Months Ended September 30,						Three Months Ended March 31,
	2004	2003	Change		% Change		2005	2004	Change		% Change
	(Thousands of MWh)						(Thousands of MWh)
Residential	1,915	2,162	(247	)	(11.4	)	1,357	1,381	(24	)	(1.7	)
Commercial	1,968	2,020	(52	)	(2.6	)	1,524	1,517	7		0.5
Industrial	1,407	1,427	(20	)	(1.4	)	1,267	1,300	(33	)	(2.5	)
Other retail	25	26	(1	)	(3.8	)	26	26	—		—

Total Retail	5,315	5,635	(320	)	(5.7	)	4,174	4,224	(50	)	(1.2	)
Tariff-based wholesale	1,299	1,371	(72	)	(5.3	)	1,253	1,068	185		17.3
Market-based wholesale	698	558	140		25.1		1,024	1,272	(248	)	(19.5	)

Total	7,312	7,564	(252	)	(3.3	)	6,451	6,564	(113	)	(1.7	)

Our retail and tariff-based wholesale customers used less energy and our sales decreased because of cooler weather. When measured by cooling degree days, the weather during the three months ended September 30, 2004 was 27% cooler than the same period last year and 23% below normal. We measure cooling degree days at weather stations we believe to be generally reflective of conditions in our service territory.

~~Market-based~~Tariff-based wholesale sales increased due primarily to ~~increased sales volumes and an approximate 16%~~the increase in ~~the average price per MWh. As a result~~MWh of ~~the milder weather, at certain times~~electricity sold. We had more energy available during the three months ended ~~September 30,~~March 31, 2005 than we did during the same period of 2004 ~~we had additional low-cost energy production available for sale that was not needed to serve our retail~~because of unplanned outages and ~~tariff-based wholesale customers. Increased sales volumes accounted for $4.5 million of~~reduced operating capability experienced at various times throughout the ~~increased market-based wholesale sales and higher average market prices accounted for $2.5 million of the increase. Changes~~three months ended March 31, 2004 at Jeffrey Energy Center.

The decrease in ~~the fair value of~~ energy marketing ~~contracts are recognized as an increase or decrease~~was due primarily to sales pursuant to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137, 138 and 149 (collectively, SFAS No. 133). We had less favorable changeshaving a net loss position in ~~2004~~2005 as compared ~~to the favorable changes~~with a net gain position in ~~2003~~2004 in the settlement and the fair value of ~~remaining~~ positions receiving mark-to-market accounting treatment. Partially offsetting the net loss position in 2005 was a $1.3 million gain recorded on the sale of emissions allowances.

Fuel expense ~~declined because we used approximately 5% less fuel for generation~~decreased due primarily to the ~~lower demand caused by the cooler weather and due to unplanned outages or reduced operating capability experienced at some~~recognition of our generating units at various times throughout the three months ended September 30, 2004. The average availability factor for our system was 93% during the three months ended September 30, 2004 compared to 95% during the three months ended September 30, 2003. Fuel expense was also reduced by a $12.3 million mark-to-market gain ~~of $3.9 million~~on fuel contracts, primarily associated with the coal supply contract for our Lawrence and Tecumseh Energy Centers. This gain was partially offset by an increase in fuel expense related to actual fuel used for generation, which increased by $6.9 million. We used approximately 1% more fuel, primarily coal, at an approximate 9% higher average cost. Lawrence Energy Center and LaCygne Generating Station experienced planned outages in 2005 and Wolf Creek experienced an unplanned outage that, together, caused us to rely on our other higher-priced generating units. At various times during the three months ended March 31, 2004, Jeffrey Energy Center experienced unplanned outages or reduced operating capability, which caused us to decrease our fuel burned and increase our purchased power. Also contributing to the higher average cost of fuel was an increase in coal transportation costs, which accounted for approximately 30% of the higher average cost.

Purchased power expense ~~increased~~decreased due primarily to ~~a 35% increase~~the decline in volumes purchased during the three months ended ~~September 30, 2004~~March 31, 2005 as compared towith the same period of ~~2003. At times, it was more economical to purchase power than to operate our available generating units. This was due to~~2004 for the ~~unavailability or reduced operating capability of our coal-fired generating units at certain times during~~reasons discussed in the ~~three months ended September 30, 2004, and the availability of economically priced power due to cooler weather in our region.~~above paragraph.

During the three months ended September 30, 2003, we recorded a pre-tax gain of $12.3 million on the sale of certain utility assets to Midwest Energy, Inc., which was recorded as an offset to operatingOperating and maintenance expense. This is the primary reason operating and maintenance expense increased during the three months ended September 30, 2004 as compared to the same period of 2003. Selling, general and administrative expense increased due primarily to an increase in ~~legal fees.~~maintenance expenses for planned outages at LaCygne Generating Station and Lawrence Energy Center. The increase in plant maintenance expense was partially offset by a decline in the maintenance expense at Jeffrey Energy Center, which was higher in 2004 due to the unplanned outage work at that plant. The remainder of the increase was caused primarily by increased maintenance of our distribution system, primarily related to higher tree trimming expense, and an increase in taxes other than income tax.

~~Other income~~Investment earnings declined due primarily to ~~the gain recorded on the sale of ONEOK stock and the ONEOK dividends received during~~lower dividend income from our investment in Guardian International, Inc. preferred stock. In the three months ended ~~September 30, 2003. This gain was partially offset~~March 31, 2004, we received a $1.4 million dividend payment on our Guardian Series C and Series E preferred stock. On July 9, 2004, Guardian redeemed its Series C preferred stock held of record by ~~the loss recorded on the extinguishment of debt during~~us. In the three months ended ~~September 30, 2003, when~~March 31, 2005, we ~~recorded a $14.2~~received $0.1 million ~~loss~~for the first quarter dividend payment on the ~~August 2003 settlement of our putable/callable notes and a $3.3 million loss on the September 2003 redemption of the Western Resources Capital II 8.5% Cumulative Quarterly Income Preferred Securities,~~Guardian Series B.

Interest expense decreased during the three months ended ~~September 30, 2004~~March 31, 2005 due to lower debt balances and lower interest rates due to the refinancing activities as discussed ~~below~~in detail in “Liquidity and Capital ~~Resources.”~~Resources” in our 2004 Form 10-K.

During the three months ended September 30, 2003, we recorded an adjustment to our estimate of the loss that we anticipated on the disposal of our discontinued operations, causing the $161.7 million loss from discontinued operations. We sold our monitored security businesses on February 17, 2004.

~~Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003:~~ Below we discuss our operating results for the nine months ended September 30, 2004 as compared to the results for the nine months ended September 30, 2003. 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, network integration, or other. Energy marketing activities are unrelated to the electricity we generate.

Our retail and tariff-based wholesale customers used less energy and our sales volumes decreased because of cooler weather. When measured by cooling degree days, the weather during the nine months ended September 30, 2004 was 13% cooler than the same period last year and 16% below normal. We measure cooling degree days at weather stations we believe to be generally reflective of conditions in our service territory. The accrual for rebates to be paid to customers in 2005 and 2006 pursuant to the July 25, 2003 KCC order also reduced retail sales. During the nine months ended September 30, 2004, we accrued $6.4 million as compared to $1.4 million accrued during the same period of 2003.

Revenues from tariff-based wholesale sales increased during the nine months ended September 30, 2004 as compared to the same period of 2003 due primarily to the recovery of higher fuel costs through a fuel adjustment provision as provided for by our FERC tariff. Market-based wholesale sales increased due to increased sales volumes. Energy marketing sales decreased due to less favorable changes in 2004 as compared to the favorable changes in 2003 in the settlement and the value of remaining positions receiving mark-to-market accounting treatment.

Fuel expense increased due primarily to increases in the cost of natural gas and oil. We used approximately 3% less fuel for generation due to the lower demand caused by the cooler weather and due to unplanned outages or reduced operating capability experienced at some of our generating units at various times throughout the nine months ended September 30, 2004. The average availability factor for our system was 89% during the nine months ended September 30, 2004 compared to 92% during the nine months ended September 30, 2003, largely due to the unavailability of some of our coal-fired generating units. As a result of the cooler weather and the reduced availability of our coal-fired generating units, the amount of coal burned declined, and consequently reduced the cost of coal. However, the cost of natural gas and oil that was used at other generating facilities to compensate for the unplanned outages or reduced operating capability, increased our total fuel expense. Fuel expense was partially reduced by a mark-to-market gain of $3.9 million associated with the coal supply contract for our Lawrence and Tecumseh Energy Centers.

~~Purchased power expense increased due primarily to a 53%~~ increase in volumes purchased during the nine months ended September 30, 2004 as compared to the same period of 2003. At times, it was more economical to purchase power than to operate our available generating units. This was due to the unavailability or reduced operating capability of our coal-fired generating units at certain times, and the availability of economically priced power due to cooler weather in our region.

During the nine months ended September 30, 2003, we recorded a pre-tax gain of $12.3 million on the sale of certain utility assets to Midwest Energy, Inc., as an offset to operating and maintenance expense. This accounted for 50% ofincome tax expense reflects the increase in operating and maintenance expense. The remaining 50% increase was caused primarily by increased expenses associated with maintenance at Jeffrey Energy Center, increased planned and unplanned unit maintenance at various other generating units, increased maintenance of the distribution system, an increase in property taxes and an increase in the SPP network costs. During the nine months ended September 30, 2004, increased maintenance of our generating units accounted for 12% of the increase in operating and maintenance expenses. The increase in distribution expenses accounted for 18% of the increase in operating and maintenance expenses. Distribution expenses increased due to increased staffing levels and higher costs associated with the termination of portions of the ONEOK shared services agreement as discussed above in Note 13, “Related Party Transactions.” The increase in property taxes accounted for 7% of the increase in operating and maintenance expenses. An increase in SPP network costs accounted for 3% of the increase in operating and maintenance expenses.income from continuing operations before income taxes.

~~Selling, general and administrative expenses increased due primarily to an increase in legal fees recorded during the nine months ended September 30, 2004.~~

The total other expense realized during 2004 was due primarily to the loss incurred on the extinguishment of debt. The total other income during 2003 was due primarily to the gain on the sale of our ONEOK stock and dividends received from ONEOK in 2003. This gain was partially offset by the loss recorded on the extinguishment of debt during the nine months ended September 30, 2003.

Interest expense decreased during the nine months ended September 30, 2004, due to lower debt balances and lower interest rates due to refinancing activities as discussed below in “Liquidity and Capital Resources.”

Income from discontinued operations was $6.9 million for the nine months ended September 30, 2004. The results recorded for the nine months ended September 30, 2004, represents an adjustment to reflect the actual loss realized on the sale of our monitored security business. This compares to a loss from discontinued operations of $51.5 million for the nine months ended September 30, 2003.

We believe we will have sufficient cash to fund future operations, ~~of our business,~~ debt maturities ~~the rebates to customers we are required to make in 2005 and 2006,~~ and the payment of dividends from a combination of cash on hand, cash flows from operations and available borrowing capacity. Our available sources of funds include cash, ~~our~~Westar Energy’s revolving credit facility, our accounts receivable conduit facility and access to capital markets. At ~~September 30, 2004,~~March 31, 2005, we had cash and cash equivalents of ~~$38.3~~$25.8 million ~~$289.3~~and $281.4 million available under ~~the~~Westar Energy’s revolving credit ~~facility and $35.0 million available under the accounts receivable conduit~~ facility. Uncertainties affecting our ability to meet these cash requirements include, among others, factors affecting sales described in “Operating Results” above, economic conditions, ~~including the impact of inflation on operating expenses,~~ regulatory actions, conditions in the capital markets and compliance with environmental regulations.

~~As of September 30, 2004,~~At March 31, 2005, our total outstanding long-term debt, net of current maturities, was approximately ~~$1.7~~$1.5 billion compared towith a balance of approximately ~~$2.1~~$1.6 billion ~~as of~~at December 31, ~~2003.~~

2004. At ~~September 30, 2004,~~March 31, 2005, our current maturities of long-term debt were ~~$71.0~~$165.0 million compared ~~to $190.7~~with $65.0 million at December 31, ~~2003. The decrease is~~2004, reflecting the classification of $100.0 million of KGE 6.2% first mortgage bonds due ~~to the $184.5 million principal amount of 6 7/8% senior unsecured notes reported as~~January 2006 in our current ~~maturities of long-term debt at December 31, 2003 that we redeemed this year.~~maturities.

We had ~~$38.3~~$25.8 million in unrestricted cash and cash equivalents at ~~September 30, 2004.~~March 31, 2005. We consider cash equivalents to be highly liquid investments with maturities of three months or less at the time they are purchased.

At ~~September 30, 2004,~~March 31, 2005, we also had ~~$14.7~~$9.6 million of restricted cash classified as a current asset and ~~$29.2~~$26.8 million of restricted cash classified as a long-term asset. The following table details our restricted cash ~~as of September 30, 2004:~~at March 31, 2005:

On May 6, 2005, Westar Energy amended and restated its revolving credit facility dated March 12, 2004 to extend the term and reduce borrowing costs. The amended and restated revolving credit facility matures on May 6, 2010. The facility allows us to borrow up to an aggregate of $350.0 million, including letters of credit up to a maximum aggregate amount of $100.0 million. So long as ~~discussed below~~there is no default or event of default under the revolving credit facility, Westar Energy may elect to increase the aggregate amount of borrowings under this facility to $500 million by increasing the commitment of one or more lenders who have agreed to such increase, or by adding one or more new lenders with the consent of the Administrative Agent and letter of credit issuing bank, which will not be unreasonably withheld. All borrowings under the revolving credit facility are secured by KGE first mortgage bonds.

A default by Westar Energy or any of its significant subsidiaries under other indebtedness totaling more than $25 million is a default under this facility. Westar Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio not greater than 0.65 to 1.0 at all times. Available liquidity under the facility is not impacted by a decline in ~~“— Short-term Debt.”~~Westar Energy’s credit ratings. Also, the facility does not contain a material adverse effect clause requiring Westar Energy to represent, prior to each borrowing, that no event resulting in a material adverse effect has occurred.

Cash flows from operating activities ~~increased $113.4~~decreased $4.6 million to ~~$278.3~~$110.2 million for the ~~nine~~three months ended ~~September 30, 2004~~March 31, 2005 from ~~$164.9~~$114.8 million for the ~~nine~~same period of 2004. During the three months ended ~~September 30, 2003. This increase was primarily attributable~~March 31, 2005, we used approximately $18.0 million for system restoration costs related to ~~reduced interest~~the ice storm that affected our service territory in January 2005 and ~~tax payments.~~we received approximately $15.0 million from the sale of accounts receivable.

In general, cash used for investing purposes relates to the growth of the operations of our electric utility business and the replacement of utility property. The utility business is capital intensive and requires significant ongoing investment in plant. ~~Cash flows used in investing activities were $12.1~~We spent $48.8 million in the ~~nine~~three months ended ~~September 30, 2004, compared to cash from investing activities of $442.6~~March 31, 2005 and $46.8 million in the ~~nine months ended September 30, 2003.~~same period of 2004 on net additions to utility property, plant and equipment. We received proceeds from the sale of Protection One of $122.2 million in the ~~nine~~three months ended ~~September 30,~~March 31, 2004. ~~We received proceeds from the sale of ONEOK stock of $540.0 million in the nine months ended September 30, 2003.~~

~~Financing~~We used $60.2 million of cash for financing activities in the ~~nine~~three months ended ~~September 30, 2004 used $308.6 million~~March 31, 2005 as compared with cash from financing activities of ~~cash compared to $594.9~~$78.3 million in the ~~nine~~same period of 2004. In the three months ended ~~September 30, 2003.~~March 31, 2005, we received cash primarily from the issuance of long-term debt, and we used cash primarily to retire long-term debt and pay dividends. In the ~~nine~~three months ended ~~September 30,~~March 31, 2004, we received cash ~~from issuances of long-term debt and~~primarily for the issuance of common stock and ~~cash was used for the retirement of long-term debt and payment of dividends. In the nine months ended September 30, 2003,~~ we used cash primarily to retire long-term debt ~~to purchase a call option investment~~ and to pay dividends.

On In the fourth quarter of 2004, we increased our quarterly dividend to $0.23 per share from $0.19 per share. The increase in the dividends paid in the three months ended March 31, ~~2004, we sold, through an underwritten public offering, 10.5 million shares of our common stock at $20.65 per share. On April 2, 2004, we sold approximately 1.6 million additional shares at~~2005 is due primarily to the ~~same price as a result of the underwriters exercising their over-allotment option on March 31, 2004. We received net cash proceeds of $239.9 million from these issuances.~~

Our pension plan expense and liabilities are measured using assumptions, which include discount rates, compensation rates and past and future estimated plan asset returns. Due to a decrease in interest rates and a corresponding decreasechange in the discount rates used to estimate our pension liabilities, the fair value of our pension plan assets may fall below the accumulated benefit obligation at our next measurement date. The combined effects of these factors could result in the recognition of additional liabilities. We anticipate that at December 31, 2004, we may be required to make additional cash contributions or to incur a charge to equity, unless we are able to obtain authority from the KCC to recognize as a regulatory asset the amount of the potential charge toquarterly dividend rate.

equity. The amounts will depend on plan asset performance for the year and the discount rate in effect when the plan liabilities are measured. We are unable to determine the financial impact at this time, which may or may not be material.

We own a 50% undivided interest in the LaCygne 1 generating unit and are the lessee of a 50% undivided interest in the LaCygne 2 generating unit, both of which are operated by Kansas City Power & Light Company (KCPL). KCPL has informed us that environmental-related equipment may be installed on these units. KCPL anticipates that costs will be incurred beginning in 2005 and continuing through the completion of installation in 2007. We expect that costs related to updating or installing emissions controls will be material. We believe that these would qualify for recovery through rates.

~~During the nine months ended September 30, 2004, we made the following changes in our long-term debt:~~

On July 22, 2004, Standard & Poor’s Ratings Group improved its ratings on KGE’s first mortgage bonds to BBB from BB+. On April 14, 2004, Moody’s Investors Service (Moody’s) affirmed its ratings for our first mortgage bonds and unsecured debt and changed its outlook of our credit ratings to positive from negative. Moody’s also raised the speculative liquidity rating it assigned to us to SGL-2 from SGL-3, reflecting its view that we have “good” liquidity. Since March 1, 2004, Fitch Investors Service has not changed its ratings for our first mortgage bonds or unsecured debt. For additional information on our credit ratings, see our 2003 Form 10-K, as amended, “Liquidity and Capital Resources — Credit Ratings.”

~~Our capital structure at September 30, 2004 and December 31, 2003 was as follows:~~

On July 28, 2000, we entered into an agreement with WR Receivables Corporation, a wholly owned, bankruptcy-remote SPE, to sell our accounts receivable arising from the sale of electricity to the SPE. These transfers are accounted for as sales in accordance with SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities.” The SPE may sell up to $125 million of an undivided interest in the accounts receivable to a third-party conduit under various terms and conditions. The percentage ownership interest in receivables held by the third-party conduit will increase or decrease over time, depending on the characteristics of the SPE’s receivables, including delinquency rates and debtor concentrations. The agreement with the third-party conduit is renewable annually upon agreement by all parties. On July 21, 2004, the agreement was extended through July 19, 2005 on substantially similar terms.

The net SPE receivables represent our retained interests in the transferred receivables and is recorded at book value, net of allowances for bad debts. This approximates fair value due to the short-term nature of the receivable. The SPE receivable is included in accounts receivable, net, on our consolidated balance sheets. The interests that we hold are included in the table below:

~~The outstanding balance of SPE receivables is net of $90.0 million at September 30, 2004 and $80.0 million at~~From December 31, ~~2003~~2004 through March 31, 2005, there have been no material changes in ~~undivided ownership interests sold by the SPE to the third-party conduit.~~our off-balance sheet arrangements. For additional information, see our 2004 Form 10-K.

From December 31, 2004 through March 31, 2005, there have been no material changes outside the ordinary course of business in our contractual obligations and commercial commitments. For additional information, see our 2004 Form 10-K.

On July 21, 2003, we entered into a Stipulation and Agreement (Stipulation) with the KCC staff and other intervenors in the docket considering the Debt Reduction Plan. The KCC issued an order approving the Stipulation on July 25, 2003. The principal terms of the Stipulation included a requirement for us to pay customer rebates of $10.5 million on May 1, 2005 and $10.0 million on January 1, 2006. We ~~have increased our contractual obligations~~will rebate $10.5 million to customers in May 2005 and $10 million in January 2006. The first rebate will appear as credits on customers’ billing statements in May and June of 2005.

At March 31, 2005, we recognized a $12.3 million gain in the market value of fuel contracts, primarily associated with the coal supply contract for ~~coal to be supplied to~~ our Lawrence and Tecumseh Energy Centers. During the first quarter of 2004, we entered into a coal supply agreement for coal to be supplied to these energy centers through 2009. We entered into this contract in the ordinary course of business and do not believe we are substantially dependent on this contract. This contract increases our contractual obligations by approximately $25.4 million per year for years 2005 through 2007 and $17.9 million for years 2008 and 2009. Based on the terms of this ~~new~~ contract, changes in the fair value of this contract are marked to market through earnings in accordance with the requirements of SFAS No. ~~149, “Amendment of Statement~~ 133, on“Accounting for Derivative Instruments and Hedging ~~Activities.~~Activities,” ~~This could cause volatility in our reported earnings.~~

~~For additional information on our contractual obligations~~as amended by SFAS Nos. 137, 138 and ~~commercial commitments, see our 2003 Form 10-K, as amended.~~

~~The following table summarizes the items that have changed significantly since December 31, 2003 in our projected future cash payments for our contractual obligations existing at September 30, 2004:~~

On March 12, 2004, we entered into a new revolving credit facility. At September 30, 2004, we had no outstanding borrowings and $10.7 million of letters of credit outstanding under the revolving credit facility. We also had $3.1 million of outstanding letters of credit secured by restricted cash.

Westar Energy is a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) as a result of Westar Energy’s ownership of KGE and Westar Generating, Inc., each a wholly-owned subsidiary. Currently, Westar Energy claims an exemption from registration under the 1935 Act based on its operations being conducted “predominantly” within the state of Kansas. Following a recent decision by the SEC with respect to its interpretation of the criteria that must be satisfied to claim a “predominantly” intrastate exemption, Westar Energy has been asked by the SEC to provide information regarding its eligibility for an exemption from registration and has responded to the SEC’s requests.

As a result of the amount of sales of wholesale electricity outside of the state of Kansas by Westar Energy’s energy marketing operations, it is possible that the SEC could question its eligibility for an exemption from registration under the 1935 Act. In that event, Westar Energy would evaluate its options, including filing an application for exemption and asking the SEC to formally consider that request, becoming a registered holding company, restructuring its operations in a manner that would allow it to maintain eligibility to claim an exemption or restructuring its organizational structure to consolidate all utility operations into one entity so that Westar Energy is no longer a utility holding company.

In the event Westar Energy elects to register, the 1935 Act and related regulations issued by the SEC would govern its activities and the activities of its subsidiaries with respect to the acquisition, issuance and sale of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters. We are unable to predict the outcome of this inquiry, however, we believe that our becoming a registered holding company under the 1935 Act or taking steps to reorganize our corporate structure to avoid registration would not have a material impact on our consolidated financial position, results of operations or cash flows.

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 (Compact), and the Compact Commission, which is responsible for causing a new disposal facility to be developed within one of the member states. The Compact Commission selected Nebraska as the host state for the disposal facility. WCNOC and the owners of the other five nuclear units in the Compact provided most of the pre-construction financing for this project. Our net investment in the Compact is approximately $7.4 million.

In December 1998, the Nebraska agencies responsible for considering the developer’s license application denied the application. The license applicant sought a hearing on the license denial, but a United States District Court indefinitely delayed proceedings related to the hearing. Most of the utilities that had provided the project’s pre-construction financing (including WCNOC) filed a federal court lawsuit contending Nebraska officials acted in bad faith while handling the license application. In September 2002, the court entered a $151.4 million judgment, about one-third of which constitutes prejudgment interest, in favor of the Compact Commission and against Nebraska, finding that Nebraska had acted in bad faith in handling the license application. On Nebraska’s appeal, the 8th Circuit, United States Court of Appeals, upheld the District Court’s decision in February 2004. Nebraska sought United States Supreme Court review of the decision. In August 2004, Nebraska and the Compact Commission settled the case under terms whereby Nebraska would pay the Compact Commission either a one-time amount of $140.5 million or four annual installments of $38.5 million beginning in August 2005. The parties agreed to dismiss all pending litigation and appeals relating to this matter. Once Nebraska makes its final payment, it will be relieved of its responsibility to host a disposal facility. Meanwhile, the Compact Commission will pursue other strategies for providing disposal capability for waste generators in the Compact region.

Nebraska no longer is a member of the Compact as a result of its notice of voluntary withdrawal given in 1999 and the Compact Commission’s 2003 revocation of the state’s membership, both of which became effective in late summer 2004.

On February 10, 2004, the Wichita City Council approved a 10-year renewal of the franchise agreement pursuant to which KGE provides retail electric service within the city of Wichita. The new 10-year franchise agreement is on terms that we believe to be reasonably similar to those previously in effect.

~~On October 1, 2004, the FERC granted regional transmission organization (RTO) status to the SPP. We are now a member of the SPP RTO.~~

~~At September 30, 2004, we recognized a $3.9 million change in the market value of the contract to supply coal to our Lawrence and Tecumseh Energy Centers through 2009.~~149 (collectively SFAS No. 133). Given the volatility in the coal market and the length of the contract term, we anticipate that we will continue to experience volatility in the market value of this contract.

The tables below show the fair value of energy marketing and fuel contracts, including the coal contract described in the preceding paragraph, that were outstanding at ~~September 30, 2004,~~March 31, 2005, their sources and maturity periods:


	Fair Value of Contracts			Fair Value of Contracts
	(In Thousands)			(In Thousands)
Net fair value of contracts outstanding at the beginning of the period	$	10,464		$	6,080
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		(7,550	)		(1,633	)
Changes in fair value of contracts outstanding at the beginning and end of the period		(1,958	)		7,516
Fair value of new contracts entered into during the period		2,067
Changes in fair value of new contracts entered into during the period					(469	)

Fair value of contracts outstanding at the end of the period	$	3,023		$	11,494

The sources of the fair values ~~of the financial instruments~~ related to these contracts are summarized in the following table:


		Fair Value of Contracts at End of Period													Fair Value of Contracts at End of Period
Sources of Fair Value		Total Fair Value			Maturity Less Than 1 Year			Maturity 1-3 Years		Maturity 4-5 Years		Maturity Over 5 Years			Total Fair Value		Maturity Less Than 1 Year			Maturity 1-3 Years		Maturity 4-5 Years
		(In Thousands)													(In Thousands)
Prices actively quoted (futures)															$	264	$	264		$	—	$	—
Prices provided by other external sources (swaps and forwards)		$	(73	)	$	(1,632	)	$	148	$	206	$	1,205			3,622		(2,268	)		3,899		1,991
Prices based on the Black Option Pricing model (options and other) (a)			3,096			(443	)		1,217		96		2,226			7,608		2,321			2,318		2,969

Total fair value of contracts outstanding		$	3,023		$	(2,075	)	$	1,365	$	302	$	3,431		$	11,494	$	317		$	6,217	$	4,960


(a) The Black Option Pricing model is a variant of the Black-Scholes Option Pricing model.	(a) The Black Option Pricing model is a variant of the Black-Scholes Option Pricing model.													(a) The Black Option Pricing model is a variant of the Black-Scholes Option Pricing model.

Share-Based Payment:In December 2004, the FASB issued SFAS No. 123R that requires companies to recognize as compensation expense the grant-date fair value of stock options and other equity-based compensation issued to employees. We will implement the provisions of the statement effective January 1, 2006.

Accounting for Conditional Asset Retirement Obligations: In March 2005, FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, 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 are currently evaluating what impact FIN 47 will likely have on our consolidated results of operations.

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory and the performance of our customers. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the Securities and Exchange Commission.

The KCC regulates many aspects of our business and operations, including the retail rates that we may charge customers for electric service. Retail rates are set by the KCC using a cost-of-service approach that takes into account historical operating expenses, fixed obligations and recovery of capital investments, including potentially stranded obligations. Using this approach, the KCC sets rates at a level calculated to recover such costs, adjusted to reflect some known and measurable changes, and a permitted return on investment. Other parties to a rate review or the KCC staff may contend that our current or proposed rates are excessive. In July 2003, the KCC approved a stipulation and agreement that required us to file for a review of our rates by May 2, 2005. Accordingly, on May 2, 2005, we filed a request for an increase in rates of $84.1 million. We expect new rates to be effective in January 2006. The rates permitted by the KCC in the rate review will determine our revenues for the succeeding periods and may have a material impact on our consolidated earnings, cash flows and financial position, as well as our ability to maintain our common stock dividend at current levels or to increase our dividend in the future. We are unable to predict the outcome of the rate review.

Once established by the KCC, our rates remain fixed until changed in a subsequent rate review, or except to the extent the KCC permits us to modify our tariffs using interim adjustment clauses. We may elect to file a rate review to request a change in our rates or intervening parties may request that the KCC review our rates for possible adjustment, subject to any limitations that may have been ordered by the KCC. Earnings could be reduced to the extent that increases in our operating costs increase more than our revenues during the period between opportunities we have to change our rates, which may occur because of maintenance and repair of plants, fuel and purchased power expenses, employee or labor costs, inflation or other factors.

The generation and transmission of electricity requires the use of expensive and complicated equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. In these events, we must either produce replacement power from more expensive units or purchase power from others at unpredictable and potentially higher cost in order to supply our customers and perform our contractual agreements. This can increase our costs and our profits. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. These factors, as well as weather, interest rates, economic conditions, fuel availability and prices, price volatility of fuel and other commodities and transportation availability and costs are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position. We engage in energy marketing transactions to reduce risk from market fluctuations, enhance system reliability and increase profits. The events mentioned above could reduce our ability to participate in energy marketing opportunities, which could reduce our profits.

We May Have Material Financial Exposure Under the Clean Air Act and Other Environmental Regulations

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated pre-construction permitting requirements under the Clean Air Act. This notification was delivered as part of an investigation by the EPA regarding maintenance activities that have been conducted since 1980 at Jeffrey Energy Center. The EPA has informed us that it has referred this matter to the DOJ for it to consider whether to pursue an enforcement action in federal district court. The remedy for a violation could include fines and penalties and an order to install new emission control systems, the associated cost of which could be material.

Our activities are subject to environmental regulation by federal, state, and local governmental authorities. These regulations generally involve the use of water, discharges of effluents into the water, emissions into the air, the handling, storage and use of hazardous substances, and waste handling, remediation and disposal, among others. Congress or the state of Kansas may enact legislation and the EPA or the state of Kansas may propose new regulations or change existing regulations that could require us to reduce emissions. Such action could require us to install costly equipment, increase our operating expense and reduce production from our plants.

Competitive Pressures from Electric Industry Deregulation Could Adversely Affect Our Revenues and Reported Earnings

We currently apply the accounting principles of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to our regulated business and at March 31, 2005 and December 31, 2004 had recorded $470.1 million and $413.7 million, respectively, of regulatory assets, net of regulatory liabilities. In the event that we determined that we could no longer apply the principles of SFAS No. 71, either as a result of the establishment of retail competition in Kansas or an expectation that permitted rates would not allow us to recover these costs, we would be required to record a charge against income in the amount of the remaining unamortized net regulatory assets.

We Face Financial Risks From Our Ownership Interest in the Wolf Creek Nuclear Facility

Risks of substantial liability arise from the ownership and operation of nuclear facilities, including, among others, potential 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 expensive units, purchase power in the open market to replace the power normally produced at Wolf Creek and we would have less power available for sale by us in the wholesale markets. Such purchases would subject us to the risk of increased energy prices and, depending on the length and cost of the outage and the level of market prices, could adversely affect our cash flow. If we were not permitted by the KCC to recover these costs, such events could have an adverse impact on our consolidated financial condition.

We and certain of our former and present directors and officers are defendants in civil litigation alleging violations of the securities laws. In addition, we continue to cooperate in investigations by a federal grand jury, the SEC and the DOJ into events that occurred at our company during the years prior to 2003. Our former president, chief executive officer and chairman and our former executive vice president and chief strategic officer have asserted significant claims against us in connection with the termination of their employment and the publication of the report of the special committee of our board of directors. An adverse result in any of these matters could result in damages, fines or penalties in amounts that could be material and adversely affect our consolidated results and financial condition. Management believes that it is not currently possible to estimate the potential impact of the ultimate resolution of these matters.

We are exposed to market risk, including market changes, changes in commodity prices, equity instrument investment prices and interest rates. From December 31, ~~2003~~2004 to ~~September 30, 2004,~~March 31, 2005, there have been no significant changes in our exposure to market ~~risk except as related to interest rates as discussed below.~~risk. For additional information, ~~on our market risk,~~ see our ~~2003~~2004 Form 10-K, ~~as amended,~~ “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

From December 31, 2003 to September 30, 2004, our variable rate debt and current maturities of fixed rate debt decreased $134.5 million. A 100 basis point change in interest rates applicable to each of these instruments would impact net income on an annualized basis by approximately $2.8 million. This represents a decline in our exposure to interest rate risk on an annualized basis of approximately $0.9 million, from $3.7 million at December 31, 2003.

Under the supervision and with the participation of management, including our chief executive officer and our chief financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and our subsidiaries is communicated to the chief executive officer and the chief financial officer. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of ~~September 30, 2004,~~March 31, 2005, our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

There were no changes in our internal controls over financial reporting during the three months ended ~~September 30, 2004~~March 31, 2005 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

On September 21, 2004, a grand jury in Travis County, Texas, indicted us on charges that a $25,000 contribution by us in May 2002 to a Texas political action committee violated Texas election laws. We believe the indictment is without any merit, and we intend to vigorously defend against the charges. If convicted, the court could impose a fine of up to $20,000 or, in certain circumstances, in an amount not to exceed twice the amount caused to be lost by the commission of the felony. As a result of the indictment, the federal government could suspend our status as a government contractor. Upon a conviction, the federal government could bar us from acting as a government contractor. We are taking action to ensure that neither of these events ~~occur,~~occurs, but we do not know whether we will be successful. We are unable to predict the ultimate impact suspension or loss of our status as a government contractor would have on our consolidated financial position, results of operations and cash flows.

Information on other legal proceedings is set forth in Notes ~~7, 8~~10, 11 and 12 of the Notes to Consolidated Financial Statements, ~~“Commitments and Contingencies — EPA New Source Review,”~~ “Legal Proceedings,” “Ongoing Investigations – Department of Labor Investigation” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Kansas				48-0290150
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification ~~Number)~~No.)


Common Stock, par value $5.00 per share		~~85,881,634~~86,620,112 shares
(Class)		(Outstanding at ~~November 1, 2004)~~May 2, 2005)


			Page
PART I.Financial Information

	Item 1.	Condensed Financial Statements (Unaudited)

		Consolidated Balance Sheets	45

		Consolidated Statements of Income	~~5-6~~6

	~~Consolidated Statements of Comprehensive Income~~	7

	Consolidated Statements of Cash Flows	87

		~~Condensed~~ Notes to Consolidated Financial Statements	98

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2019

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3330

	Item 4.	Controls and Procedures	3330

PART II.Other Information

	Item 1.	Legal Proceedings	3431

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3431

	Item 3.	Defaults Upon Senior Securities	3431

	Item 4.	Submission of Matters to a Vote of Security Holders	3431

	Item 5.	Other Information	3431

	Item 6.	Exhibits	3432

~~Signature~~	35Signature		33


	Nine Months Ended September 30,
	2004			2003
SALES	$	1,120,181		$	1,129,485

OPERATING EXPENSES:

Fuel and purchased power		320,892			300,040
Operating and maintenance		300,460			275,839
Depreciation and amortization		126,649			125,435
Selling, general and administrative		123,668			118,897

Total Operating Expenses		871,669			820,211

INCOME FROM OPERATIONS		248,512			309,274

OTHER INCOME (EXPENSE):
Investment earnings		12,543			28,021
Gain on sale of ONEOK, Inc. stock		—			53,822
Loss on extinguishment of debt and settlement of putable/callable notes		(18,840	)		(26,425	)
Other income		2,066			1,694
Other expense		(11,295	)		(13,498	)

Total Other Income (Expense)		(15,526	)		43,614

Interest expense		112,203			175,786

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		120,783			177,102

Income tax expense		37,644			54,609

INCOME FROM CONTINUING OPERATIONS		83,139			122,493

Results of discontinued operations, net of tax		6,888			(51,451	)

NET INCOME		90,027			71,042

Preferred dividends, net of gain on reacquired preferred stock		727			686

EARNINGS AVAILABLE FOR COMMON STOCK	$	89,300		$	70,356

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):
Basic earnings available from continuing operations	$	1.01		$	1.68
Results of discontinued operations		0.08			(0.71	)

Basic earnings available	$	1.09		$	0.97

Diluted earnings available from continuing operations	$	1.00		$	1.67
Results of discontinued operations		0.08			(0.71	)

Diluted earnings available	$	1.08		$	0.96

Average equivalent common shares outstanding		81,849,084			72,299,260

DIVIDENDS DECLARED PER COMMON SHARE	$	0.57		$	0.57


	Three Months Ended September 30,
	2004						2003
NET INCOME (LOSS)				$	60,369					$	(81,067	)

OTHER COMPREHENSIVE LOSS, BEFORE TAX:
Unrealized holding (loss) gain on marketable securities arising during the period	$	(6	)				$	20,736
Reclassification adjustment for gain included in net income		—			(6	)		(38,522	)		(17,786	)

Unrealized holding loss on cash flow hedges arising during the period		—						(2,931	)
Reclassification adjustment for gain included in net income		—			—			(6,166	)		(9,097	)

Other comprehensive loss, before tax					(6	)					(26,883	)

Income tax benefit related to items of other comprehensive income					—						10,694

Other comprehensive loss, net of tax					(6	)					(16,189	)

COMPREHENSIVE INCOME (LOSS)				$	60,363					$	(97,256	)


	Nine Months Ended September 30,
	2004						2003
NET INCOME				$	90,027					$	71,042

OTHER COMPREHENSIVE INCOME, BEFORE TAX:
Unrealized holding gain on marketable securities arising during the period	$	27					$	55,038
Reclassification adjustment for gain included in net income		—			27			(53,805	)		1,233

Unrealized holding gain on cash flow hedges arising during the period		—						13,851
Reclassification adjustment for gain included in net income		—			—			(7,276	)		6,575

Other comprehensive income, before tax					27						7,808

Income tax expense related to items of other comprehensive income					—						(3,107	)

Other comprehensive gain, net of tax					27						4,701

COMPREHENSIVE INCOME				$	90,054					$	75,743


	December 31, 2003
	(In Thousands)
Assets:
Current	$	80,850
Property and equipment		60,656
Customer accounts, net		268,533
Goodwill, net		41,847
Other		118,655

Total assets	$	570,541

Liabilities:
Current	$	68,816
Long-term debt		305,234
Other long-term liabilities		101,547

Total liabilities	$	475,597


	(In Thousands, Except Per Share Amounts)
Sales	$	22,466
Costs and expenses		19,937

Earnings from discontinued operations before income taxes		2,529
Estimated gain on disposal		4,115
Income tax benefit		(244	)

Results of discontinued operations	$	6,888

Basic and diluted results of discontinued operations per share	$	0.09


	Balance as of December 31, 2003		Securities Redeemed			Securities Issued		Balance as of September 30, 2004
	(In Thousands)
Westar Energy
First mortgage bond series:
6.00% due 2014	$	—	$	—		$	250,000	$	250,000
8.5% due 2022		125,000		(125,000	)		—		—
7.65% due 2023		100,000		(100,000	)		—		—

Pollution control bond series:
6.00% due 2033		58,340		(58,340	)		—		—
5.00% due 2033		—		—			58,340		58,340

6 7/8% senior unsecured notes due August 1, 2004		184,456		(184,456	)		—		—
9 3/4% senior unsecured notes due 2007		387,000		(127,000	)		—		260,000
6.80% senior unsecured notes due 2018		26,993		(26,993	)		—		—
Senior secured term loan due 2005		114,143		(114,143	)		—		—

	$	995,932	$	(735,932	)	$	308,340	$	568,340

KGE
Pollution control bond series:
7.00% due 2031	$	327,500	$	(327,500	)	$	—	$	—
5.30% due 2031		—		—			108,600		108,600
2.65% due 2031 and putable 2006		—		—			100,000		100,000
5.30% due 2031		—		—			18,900		18,900
Variable rate due 2031		—		—			100,000		100,000

	$	327,500	$	(327,500	)	$	327,500	$	327,500

Long-term debt affiliate	$	103,093	$	(103,093	)	$	—	$	—


	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2005			2004			2005			2004
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,630		$	1,509		$	563		$	368
Interest cost		7,174			7,021			1,861			1,868
Expected return on plan assets		(9,056	)		(9,644	)		(645	)		(533	)
Amortization of:
Transition obligation, net		—			—			983			983
Prior service costs		691			688			(117	)		(117	)
Loss, net		1,367			601			530			481

Net periodic cost	$	1,806		$	175		$	3,175		$	3,050


	Electric Utility		Other (a)			Total
	(In Thousands, Except Per Share Amounts)
Sales	$	438,167	$	—		$	438,167

Earnings (loss) per share	$	0.79	$	(1.91	)	$	(1.12	)

(a) Earnings (loss) per share include investment earnings of $3.2 million of ONEOK preferred dividends, $0.8 million of ONEOK common stock dividends and $38.5 million on the sale of ONEOK stock.


ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


	Restricted Cash
	Current		Long-term
	(In Thousands)
Prepaid capacity and transmission agreement	$	2,213	$	26,561
Collateralized letters of credit		—		400
Collateralized surety bonds		—		2,222
Cash held in escrow as required by certain letters of credit, surety bonds and various other deposits		12,510		—

Total	$	14,723	$	29,183


	Restricted Cash Current Portion		Restricted Cash Long-term Portion
	(In Thousands)
Prepaid capacity and transmission agreement	$	2,297	$	25,391
Cash held in escrow as required by surety bonds and various other deposits		7,307		1,432

Total	$	9,604	$	26,823


	September 30, 2004		December 31, 2003
Common equity	43	%	31	%
Preferred stock	1	%	1	%
Debt	56	%	68	%

Total	100	%	100	%


	Total		October 1, 2004 through December 31, 2004		2005 - 2006		2007 - 2008		Thereafter
	(In Thousands)
Fossil fuel (a)	$	2,017,807	$	23,071	$	388,239	$	294,250	$	1,312,247

(a) Coal and natural gas commodity and transportation contracts.



4		Forty-Fourth Supplemental Indenture dated May 6, 2005 between Kansas Gas and Electric Company and BNY Midwest Trust Company, as Trustee

10		Amended and Restated Credit Agreement dated as of May 6, 2005 among Westar Energy, Inc., the several banks and other financial institutions or entities from time to time parties to the Agreement, JPMorgan Chase Bank, N.A., as administrative agent, The Bank of New York, as syndication agent, and Citibank, N.A., Union Bank of California, N.A., and Wachovia Bank, National Association, as documentation agents

31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended ~~September 30, 2004~~March 31, 2005

31(b)		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended ~~September 30, 2004~~March 31, 2005

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended ~~September 30, 2004~~March 31, 2005 (furnished and not to be considered filed as part of the Form 10-Q)