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Form U-3A-2/A


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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM U-3A-2/A

Statement by Holding Company Claiming Exemption Under Rule U-3A-2 from the Provisions of the

Public Utility Holding Company Act of 1935

To Be Filed Annually Prior to March 1

WESTAR ENERGY, INC.

Westar Energy, Inc. (Westar Energy) hereby files with the Securities and Exchange Commission, pursuant to Rule 2, its statement claiming exemption as a holding company from the provisions of the Public Utility Holding Company Act of 1935 (the Act) and submits the following information.

ITEM 1. Name, State of organization, location and nature of business of claimant and every subsidiary thereof, other than any exempt wholesale generator (EWG) or foreign utility company in which claimant directly or indirectly holds an interest.

Westar Energy is a Kansas corporation whose principal executive offices are located at 818 South Kansas Avenue, Topeka, Kansas 66612. Westar Energy’s mailing address is P.O. Box 889, Topeka, Kansas 66601. During 2004, Westar Energy’s principal business consisted of the production, purchase, transmission, distribution and sale of electricity. Westar Energy provided retail electric service to approximately 352,000 residential, industrial and commercial customers located in Kansas. Westar Energy also provided wholesale electric generation and transmission services to numerous municipal customers located in Kansas and to entities outside of Kansas through interconnections located within and outside of Kansas. As of December 31, 2004, Westar Energy’s subsidiaries (as defined in the Act) were as follows:

Kansas Gas and Electric Company (KGE) is a Kansas corporation with principal offices at 120 East First Street, Wichita, Kansas 67201. KGE is a wholly owned subsidiary of Westar Energy and provides electric services to customers in the south central and southeastern portion of Kansas, including the city of Wichita. During 2004, KGE provided retail electric services to approximately 301,000 residential, commercial and industrial customers located in Kansas. KGE also provided wholesale electric generation and transmission services to numerous municipal customers located in Kansas and to entities outside of Kansas through interconnections located within and outside of Kansas. KGE does not own or operate any gas properties. KGE owns a 47% interest in the following company:

Wolf Creek Nuclear Operating Corporation (WCNOC) is a Delaware Corporation with principal offices at 1550 Oxen Lane, N.E., Burlington, Kansas 66839. WCNOC operates the Wolf Creek Nuclear Generating Station on behalf of the plant’s owners.

B.	Westar Generating, Inc. (Westar Generating) is a Kansas corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Westar Generating is a wholly owned subsidiary of Westar Energy and holds a 40% interest in the State Line electric generating facility.

Westar Industries, Inc. (Westar Industries) is a Delaware corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Westar Industries is a wholly owned subsidiary of Westar Energy and is a holding company for certain non-regulated business subsidiaries of Westar Energy.

Western Resources (Bermuda), Ltd. (WR Bermuda) is a limited liability company formed under the laws of Bermuda with principal offices at Clarendon House, Two Church Street, Hamilton HM 11, Bermuda. WR Bermuda is a wholly owned subsidiary of Westar Energy. WR Bermuda holds interests in international power projects. WR Bermuda holds interests in the following companies:

CPI-Western Power Holdings, Ltd. (CPI) is a limited liability company formed under the laws of Bermuda with principal offices at Clarendon House, Two Church Street, Hamilton HM 11, Bermuda. WR Bermuda owns 50% of CPI, which is a joint venture that holds interests in power generation projects in China. CPI owns 100% of the following company:

Western Resources International, Ltd. (WRIL) is a limited liability company organized under the laws of Mauritius. WRIL holds interests in the following EWGs:

Zhengzhou Dengwei Power Company, Ltd. is a corporation organized under the laws of China, with principal offices at Yangcheng Industrial Zone, Dengfeng Industrial Zone, Dengfeng Municipality, Henan Province, People’s Republic of China. This company is an EWG and 49% owned by WRIL.

ii.

Zhengzhou Dengyuan Power Company, Ltd. is a corporation organized under the laws of China, with principal offices at Yangcheng Industrial Zone, Dengfeng Municipality, Henan Province, People’s Republic of China. This company is an EWG and 49% owned by WRIL.

iii.

Zhengzhou Huadeng Power Company, Ltd. is a corporation organized under the laws of China, with principal offices at Yangcheng Industrial Zone, Dengfeng Industrial Zone, Dengfeng Municipality, Henan Province, People’s Republic of China. This company is an EWG and 49% owned by WRIL.

iv.

Zhengzhou Huaxin Power Company, Ltd. is a corporation organized under the laws of China, with principal offices at Yangcheng Industrial Zone, Dengfeng Industrial Zone, Dengfeng Municipality, Henan Province, People’s Republic of China. This company is an EWG and 49% owned by WRIL.

WR Receivables Corporation (WR Receivables) is a Kansas corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. WR Receivables is a wholly owned subsidiary of Westar Energy and a special purpose entity that, pursuant to an agreement with a group of financial institutions, acts as a conduit for the sale of the accounts receivables arising from the sale of electricity by Westar Energy and KGE to such financial institutions.

F.	Inactive companies and companies with immaterial assets and liabilities:

AV One, Inc. (AV One) is a Kansas corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. AV One is a dormant, wholly owned subsidiary of Westar Energy that was formerly an aviation services company.

Consultron Nederland Teleshop B.V. (Consultron) is a corporation organized under the laws of the Netherlands with principal offices at Markendaalseweg 329, Boite19, NL, 4811KB Breda, Netherlands. Consultron is a dormant, wholly owned subsidiary of Westar Energy that was formerly a monitored security company.

Protection One International, Inc. (PO International) is a Delaware corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. PO International is a wholly owned subsidiary of Westar Industries that holds an escrow account relating to formerly-held international security alarm service companies.

Residentie Alarmcentrale B.V. (Residentie) is a corporation organized under the laws of the Netherlands with principal offices at Jupiterkade 2 A, NL, 2516 ES Den Haag, The Netherlands. Residentie is a dormant, wholly owned subsidiary of Consultron that was formerly a monitored security company.

The Kansas Power and Light Company (KPL) is a Kansas corporation with its principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. KPL is a dormant, wholly owned subsidiary of Westar Energy that is maintained to retain rights to the corporate name.

The Wing Group International, Inc. (WGII) is an organization formed under the laws of the Cayman Islands with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. WGII is a dormant, wholly owned subsidiary of The Wing Group, Limited Company that was established to develop power generation projects.

The Wing Group, Limited Company (WGLC) is a Delaware corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. WGLC is a wholly owned subsidiary of Westar Industries that, during 2004, held interests in international power generation projects.

Westar Investments, Inc. (Westar Investments) is a Delaware corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Westar Investments is a wholly owned subsidiary of Westar Industries that holds security-related investments.

Westar Limited Partners, Inc. (WLP) is a Kansas corporation with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. WLP is a wholly owned subsidiary of Westar Industries that holds non-regulated investments associated with former partnerships.

10.

Western Resources I (Cayman Islands), Ltd. (Cayman I) is a limited liability company organized under the laws of the Cayman Islands with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Cayman I is a dormant, wholly owned subsidiary of WR Bermuda that was established to develop power generation projects.

11.

Western Resources II (Cayman Islands), Ltd. (Cayman II) is a limited liability company organized under the laws of the Cayman Islands with principal offices at 818 South Kansas Avenue, Topeka, Kansas 66612. Cayman II is a dormant, wholly owned subsidiary of Cayman I that was established to develop power generation projects.

ITEM 2. Description of The Properties of Claimant And Each of Its Subsidiary Public Utility Companies Used for the Generation, Transmission, and Distribution of Electric Energy for Sale.

A.	The principal electric generating stations of Westar Energy, all of which are located in Kansas, are as follows:


Name and Location		Accredited Capacity – MW (Westar Energy’s Share)
Coal
Jeffrey Energy Center, St. Marys		1,416.0
Lawrence Energy Center, Lawrence		548.0
Tecumseh Energy Center, Tecumseh		204.0

Subtotal		2,168.0

Gas/Oil
Gordon Evans, Colwich		299.0
Hutchinson Energy Center, Hutchinson		399.0
Abilene Energy Center, Abilene		72.0
Tecumseh Energy Center, Tecumseh		38.0

Subtotal		808.0

Diesel
Hutchinson Energy Center		80.0

Wind
Jeffrey Energy Center, St. Marys		1.0

Total Accredited Capacity		3,057.0

Westar Energy maintains 14 tie lines with 6 other public utilities to permit direct extra-high voltage interchange. Westar Energy is also a member of the Southwest Power Pool, the regional transmission organization for numerous electric utilities throughout the south-central United States.

Westar Energy owns a transmission and distribution system, that enables it to supply its service area. Transmission and distribution lines, in general, are located by permit or easement on public roads and streets or the lands of others. All such transmission and distribution systems are located within Kansas.

B.	The principal electric generating stations of KGE, all of which are located in Kansas, are as follows:


Name and Location		Accredited Capacity – MW (KGE’s Share)
Nuclear
Wolf Creek Generating Station, Burlington		548.0

Coal
LaCygne Station, LaCygne		681.0
Jeffrey Energy Center, St. Marys		443.0

Subtotal		1,124.0

Gas/Oil
Gordon Evans Energy Center, Colwich		532.0
Murray Gill Energy Center, Wichita		317.0
Neosho Energy Center, Parsons		63.0

Subtotal		912.0

Diesel
Gordon Evans Energy Center, Colwich		3.0

Wind
Jeffrey Energy Center, St. Marys		0.2

Total Accredited Capacity		2,587.2

KGE maintains 13 tie lines with 7 other public utilities to permit direct extra-high voltage interchange. Since KGE provides electric service together with the electric utility operations of Westar Energy, KGE is a member of the Southwest Power Pool through Westar Energy’s membership and does not have a separate membership.

KGE owns a transmission and distribution system that enables it to supply its service area. Transmission and distribution lines, in general, are located by permit or easement on public roads and streets or the lands of others. All such transmission and distribution systems are located within Kansas.

C.	The principal electric generating stations of Westar Generating, all of which are located in Missouri and the output of which is wholly dedicated under a long-term contract to its parent, Westar Energy, are as follows:


Name and Location		Accredited Capacity – MW (Westar Generating’s share)
Gas
State Line, Joplin		200.0

ITEM 3. Information for the Last Calendar Year with Respect to Claimant and Each of its Subsidiary Public Utility Companies.

A.	Number of KWH of electric energy sold (at retail or wholesale), and MCF of natural or manufactured gas distributed at retail:

For the year ended December 31, 2004, Westar Energy sold 9,225,171,000 KWH of electric energy at retail and 5,466,439,000 KWH of electric energy at wholesale. For the year ended December 31, 2004, KGE sold 9,138,913,000 KWH of electric energy at retail and 3,220,981,000 KWH of electric energy at wholesale. In addition, for the year ended December 31, 2004, Westar Energy’s energy marketing group sold 8,895,048,000 KWH of electric energy at wholesale. For the year ended December 31, 2004, Westar Generating sold 230,764,000 KWH of electric energy at wholesale, all of which was sold to its parent, Westar Energy. For the year ended December 31, 2004, neither Westar Energy nor its subsidiaries distributed natural or manufactured gas at retail.

B.	Number of KWH of electric energy and MCF of natural or manufactured gas distributed at retail outside the State in which each company is organized:

For the year ended December 31, 2004, neither Westar Energy nor its subsidiaries distributed or sold electric energy or natural or manufactured gas at retail outside of Kansas.

C.	Number of KWH of electric energy and MCF of natural and manufactured gas sold at wholesale outside the State in which each company is organized:

For the year ended December 31, 2004, Westar Energy sold, at wholesale, 859,039,000 KWH of electric energy to entities outside of Kansas through interconnections located both within and outside of Kansas. For the year ended December 31, 2004, KGE sold, at wholesale, 2,603,594,000 KWH of electric energy to entities outside of Kansas through interconnections located both within and outside of Kansas. In addition, for the year ended December 31, 2004, Westar Energy’s energy marketing group sold 8,895,048,000 KWH of electric energy at wholesale to entities outside of Kansas. For the year ended December 31, 2004, Westar Generating sold 230,764,000 KWH of electric energy at wholesale, all of which was sold to its parent, Westar Energy. For the year ended December 31, 2004, neither Westar Energy nor its subsidiaries owned any natural or manufactured gas distribution assets and did not sell any natural or manufactured gas at wholesale outside the state of Kansas, except for sales of natural or manufactured gas that were completed in connection with trading or hedging activities or used in electric generating facilities.

D.	Number of KWH of electric energy and MCF of natural or manufactured gas purchased outside the State in which each company is organized:

For the year ended December 31, 2004, Westar Energy purchased 558,999,000 KWH of electric energy from outside of Kansas or at the Kansas state line including 230,764,000 KWH of electric energy it purchased from its wholly owned subsidiary, Westar Generating. For the year ended December 31, 2004, KGE purchased 512,215,000 KWH of electric energy from outside of the state of Kansas or at the Kansas state line. In addition, for the year ended December 31, 2004, Westar Energy’s energy marketing group purchased 8,972,669,000 KWH of electric energy at wholesale. For the year ended December 31, 2004, neither Westar Energy nor its subsidiaries owned any natural or manufactured gas distribution assets and did not purchase any natural or manufactured gas from outside the state of Kansas, except for purchases of natural or manufactured gas that were completed in connection with energy marketing activities or used in electric generating facilities.

ITEM 4. Information for the Reporting Period with Respect to Claimant and Each Interest it Holds Directly or Indirectly in an EWG or a Foreign Utility Company.

4.1

Zhengzhou Dengwei Power Company, Ltd.

A.	Name, location, business address and description of the facilities used by the EWG or foreign utility company for the generation, transmission and distribution of electric energy for sale or for the distribution at retail of natural or manufactured gas:


Name of EWG:		Zhengzhou Dengwei Power Company, Ltd.
Address:		Yangcheng Industrial Zone
		Dengfeng Industrial Zone,
		Dengfeng Municipality, Henan Province
Location:		Dengfeng Municipality, Henan Province, People’s Republic of China
Facility:		55 MW coal-fired generating unit

B.	Name of each system company that holds an interest in such EWG or foreign utility company; and description of the interest held:

WRIL owns a 49% interest in Zhengzhou Dengwei Power Company, Ltd.

Type and amount of capital invested, directly or indirectly, by the holding company claiming exemption; any direct or indirect guarantee of the security of the EWG or foreign utility company by the holding company claiming exemption; and any debt or other financial obligation for which there is recourse, directly or indirectly, to the holding company claiming exemption or another system company, other than the EWG or foreign utility company:


Capital Invested:		Approximately US $5.2 million as registered paid-in capital
Guarantees:		None
Other Obligations:		None

D.	Capitalization and earnings of the EWG or foreign utility company during the reporting period:


Capitalization:		US $14.8 million
Earnings:		US $1.4 million

E.	Identify any service, sales or construction contract(s) between the EWG or foreign utility company and a system company, and describe the services to be rendered or goods sold and fees or revenues under such agreement(s):

None

4.2

Zhengzhou Dengyuan Power Company, Ltd.

A.	Name, location, business address and description of the facilities used by the EWG or foreign utility company for the generation, transmission and distribution of electric energy for sale or for the distribution at retail of natural or manufactured gas:


Name of EWG:		Zhengzhou Dengyuan Power Company, Ltd.
Address:		Yangcheng Industrial Zone,
		Dengfeng Municipality, Henan Province
Location:		Dengfeng Municipality, Henan Province, People’s Republic of China
Facility:		55 MW coal-fired generating unit

B.	Name of each system company that holds an interest in such EWG or foreign utility company; and description of the interest held:

WRIL owns a 49% interest in Zhengzhou Dengyuan Power Company, Ltd.


Capital Invested:		Approximately US $4.9 million as registered paid-in capital
Guarantees:		None
Other Obligations:		None

D.	Capitalization and earnings of the EWG or foreign utility company during the reporting period:


Capitalization:		US $14.8 million
Earnings:		US $1.9 million

E.	Identify any service, sales or construction contract(s) between the EWG or foreign utility company and a system company, and describe the services to be rendered or goods sold and fees or revenues under such agreement(s):

None

4.3

Zhengzhou Huadeng Power Company, Ltd.

A.	Name, location, business address and description of the facilities used by the EWG or foreign utility company for the generation, transmission and distribution of electric energy for sale or for the distribution at retail of natural or manufactured gas:


Name of EWG:		Zhengzhou Huadeng Power Company, Ltd.
Address:		Yangcheng Industrial Zone
		Dengfeng Industrial Zone
		Dengfeng Municipality, Henan Province
Location:		Dengfeng Municipality, Henan Province, People’s Republic of China
Facility:		55 MW coal-fired generating unit

B.	Name of each system company that holds an interest in such EWG or foreign utility company; and description of the interest held:

WRIL owns a 49% equity interest in Zhengzhou Huadeng Power Company, Ltd.


Capital Invested:		Approximately US $4.4 million as registered paid-in capital
Guarantees:		None
Other Obligations:		None

D.	Capitalization and earnings of the EWG or foreign utility company during the reporting period:


Capitalization:		Registered paid-in capital of approximately US $14.8 million
Earnings:		US $2.1 million

E.	Identify any service, sales or construction contract(s) between the EWG or foreign utility company and a system company, and describe the services to be rendered or goods sold and fees or revenues under such agreement(s):

None

4.4

Zhengzhou Huaxin Power Company, Ltd.

A.	Name, location, business address and description of the facilities used by the EWG or foreign utility company for the generation, transmission and distribution of electric energy for sale or for the distribution at retail of natural or manufactured gas:


Name of EWG:		Zhengzhou Huaxin Power Company, Ltd.
Address:		Yangcheng Industrial Zone
		Dengfeng Industrial Zone
		Dengfeng Municipality, Henan Province
Location:		Dengfeng Municipality, Henan Province, People’s Republic of China
Facility:		55 MW coal-fired generating unit

B.	Name of each system company that holds an interest in such EWG or foreign utility company; and description of the interest held:

WRIL owns a 49% equity interest in Zhengzhou Huaxin Power Company, Ltd.


Capital Invested:		Approximately US $4.4 million as registered paid-in capital
Guarantees:		None
Other Obligations:		None

D.	Capitalization and earnings of the EWG or foreign utility company during the reporting period:


Capitalization:		Registered paid-in capital of approximately US $14.8 million
Earnings:		US $1.8 million

E.	Identify any service, sales or construction contract(s) between the EWG or foreign utility company and a system company, and describe the services to be rendered or goods sold and fees or revenues under such agreement(s):

None

The above-named claimant has caused this statement to be duly executed on its behalf by its authorized officer on this 16^th day of March, 2005.


Westar Energy, Inc.

By:		/s/ Mark A. Ruelle
		Mark A. Ruelle,
		Executive Vice President and
		Chief Financial Officer

CORPORATE SEAL

Attest:


By:		/s/ Larry D. Irick
		Larry D. Irick,
		Vice President, General Counsel and
		Corporate Secretary

Name, title and address of officer to whom notices and correspondence concerning this statement should be addressed:

Larry D. Irick

Vice President, General Counsel and Corporate Secretary

Westar Energy, Inc.

P.O. Box 889

818 South Kansas Avenue

Topeka, Kansas 66601

(785)575-1625

(785)575-8136 (FAX)

EXHIBIT A

A consolidating statement of income and surplus of the claimant and its subsidiary companies for the last calendar year, together with a consolidating balance sheet of claimant and its subsidiary companies as of the close of such calendar year.

A-1

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004


	Westar Energy, Inc.			Kansas Gas and Electric Company			WR Receivables Corporation		Westar Generating, Inc.		AV One, Inc.
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	19,861,250		$	14,934		$	796,929	$	—	$	—
Restricted cash		12,256,692			21,933			—		—		—
Accounts receivable, net		(74,695,456	)		(29,773,382	)		34,587,627		29,601,425		—
Inventories and supplies		59,447,418			64,397,016			—		718,447		—
Energy marketing contracts		19,134,318			4,020,248			—		—		—
Tax receivable		—			—			—		—		—
Deferred tax assets		7,082,106			871,977			—		—		—
Prepaid expenses		5,242,387			24,010,709			58,914		117,043		—
Other		8,862,239			2,754,182			—		—		—

Total Current Assets		57,190,954			66,317,617			35,443,470		30,436,915		—

PROPERTY, PLANT AND EQUIPMENT, NET		1,468,280,346			2,349,672,524			—		93,034,007		—

OTHER ASSETS:
Restricted cash		27,407,598			—			—		—		—
Regulatory assets		121,584,993			321,359,442			—		—		—
Nuclear decommissioning trust		—			91,094,902			—		—		—
Energy marketing contracts		4,737,083			166,418			—		—		—
Other		1,485,009,528			40,136,949			—		34,350		—

Total Other Assets		1,638,739,202			452,757,711			—		34,350		—

TOTAL ASSETS	$	3,164,210,502		$	2,868,747,852		$	35,443,470	$	123,505,272	$	—

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	65,000,000		$	—	$	—	$	—
Accounts payable		29,759,982			39,772,006			4,034,738		1,791,364		—
Accrued taxes		(33,165,911	)		27,752,617			1,667,316		287,703		—
Energy marketing contracts		17,934,316			2,496,745			—		—		—
Accrued interest		23,406,189			7,099,893			350,555		—		—
Other		69,340,126			29,909,497			498,135		—		—

Total Current Liabilities		107,274,702			172,030,758			6,550,744		2,079,067		—

LONG-TERM LIABILITIES:
Long-term debt, net		1,152,482,791			487,418,472			—		—		—
Unamortized investment tax credits		22,884,280			46,072,848			—		—		—
Deferred income taxes		272,960,841			656,838,124			—		4,356,782		—
Deferred gain from sale-leaseback		—			138,981,389			—		—		—
Accrued employee benefits		91,843,112			28,308,921			—		—		—
Asset retirement obligation		—			87,117,937			—		—		—
Nuclear decommissioning		—			91,094,902			—		—		—
Energy marketing contracts		1,482,868			63,993			—		—		—
Other		106,073,287			77,507,813			—		—		—

Total Long-Term Liabilities		1,647,727,179			1,613,404,399			—		4,356,782		—

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY:
Cumulative preferred stock		21,436,300			—			—		—		—
Common stock		430,148,605			1,065,633,791			1,000		1,000		1,000
Paid-in capital		912,931,897			—			20,399,048		94,919,255		12,552,005
Unearned compensation		(10,361,158	)		—			—		—		—
Retained earnings (accumulated deficit)		55,052,977			17,678,904			8,492,678		22,149,168		(12,553,005	)
Accumulated other comprehensive income, net		—			—			—		—		—

Total Shareholders’ Equity		1,409,208,621			1,083,312,695			28,892,726		117,069,423		—

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,164,210,502		$	2,868,747,852		$	35,443,470	$	123,505,272	$	—

A-2

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004


	Western Resources (Bermuda), Ltd.			Westar Industries, Inc. Consolidated			Consolidating Entries			Westar Energy, Inc. Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,627,584		$	2,310,746		$	—		$	24,611,443
Restricted cash		—			—			—			12,278,625
Accounts receivable, net		—			102,620,771			30,191,372			92,532,357
Inventories and supplies		—			—			—			124,562,881
Energy marketing contracts		—			—			—			23,154,566
Tax receivable		—			—			90,845,235			90,845,235
Deferred tax assets		—			—			(736,315	)		7,217,768
Prepaid expenses		—			—			(250,000	)		29,179,053
Other		283,548			8,267			(350,555	)		11,557,681

Total Current Assets		1,911,132			104,939,784			119,699,737			415,939,609

PROPERTY, PLANT AND EQUIPMENT, NET		—			—			—			3,910,986,877

OTHER ASSETS:
Restricted cash		—			—			—			27,407,598
Regulatory assets		—			—			—			442,944,435
Nuclear decommissioning trust		—			—			—			91,094,902
Energy marketing contracts		—			—			—			4,903,501
Other		—			7,068,611			(1,339,815,421	)		192,434,017

Total Other Assets		—			7,068,611			(1,339,815,421	)		758,784,453

TOTAL ASSETS	$	1,911,132		$	112,008,395		$	(1,220,115,684	)	$	5,085,710,939

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	—		$	—		$	65,000,000
Accounts payable		—			43,491			30,191,372			105,592,953
Accrued taxes		—			10,487,020			90,845,235			97,873,980
Energy marketing contracts		—			—			—			20,431,061
Accrued interest		—			—			(350,555	)		30,506,082
Other		—			408,216			(986,315	)		99,169,659

Total Current Liabilities		—			10,938,727			119,699,737			418,573,735

LONG-TERM LIABILITIES:
Long-term debt, net		—			—			—			1,639,901,263
Unamortized investment tax credits		—			—			—			68,957,128
Deferred income taxes		—			—			(7,068,611	)		927,087,136
Deferred gain from sale-leaseback		—			—			—			138,981,389
Accrued employee benefits		—			—			—			120,152,033
Asset retirement obligation		—			—			—			87,117,937
Nuclear decommissioning		—			—			—			91,094,902
Energy marketing contracts		—			—			—			1,546,861
Other		—			—			(604,173	)		182,976,927

Total Long-Term Liabilities		—			—			(7,672,784	)		3,257,815,576

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY:
Cumulative preferred stock		—			—			—			21,436,300
Common stock		—			731,971			(1,066,368,762	)		430,148,605
Paid-in capital		14,619,464			699,138,054			(841,627,826	)		912,931,897
Unearned compensation		—			—			—			(10,361,158	)
Retained earnings (accumulated deficit)		(12,821,339	)		(598,800,357	)		575,853,951			55,052,977
Accumulated other comprehensive income, net		113,007			—			—			113,007

Total Shareholders’ Equity		1,911,132			101,069,668			(1,332,142,637	)		1,409,321,628

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,911,132		$	112,008,395		$	(1,220,115,684	)	$	5,085,710,939

A-3

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING STATEMENTS OF INCOME

Year Ended December 31, 2004


	Westar Energy, Inc.			Kansas Gas and Electric Company			WR Receivables Corporation			Westar Generating, Inc.
SALES	$	748,395,775		$	714,939,427		$	—		$	30,223,763

OPERATING EXPENSES:
Fuel and purchased power		253,220,533			181,039,204			—			11,490,630
Operating and maintenance		185,829,221			229,581,638			5,015			4,618,477
Depreciation and amortization		73,113,373			91,835,072			—			4,361,071
Selling, general and administrative		96,464,308			71,475,233			3,629,689			939,462

Total Operating Expenses		608,627,435			573,931,147			3,634,704			21,409,640

INCOME FROM OPERATIONS		139,768,340			141,008,280			(3,634,704	)		8,814,123

OTHER INCOME (EXPENSE):
Investment earnings		171,179,155			2,361,833			—			—
Loss on extinguishment of debt		(18,839,843	)		—			—			—
Other income		(21,694,861	)		(8,045,003	)		32,546,540			—
Other expense		—			(12,765,894	)		(2,114,243	)		—

Total Other Income (Expense)		130,644,451			(18,449,064	)		30,432,297			—

Interest expense		112,347,120			29,621,139			3,950,158			19,735

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		158,065,671			92,938,077			22,847,435			8,794,388
Income tax expense (benefit)		(2,781,325	)		25,353,404			9,204,558			3,315,399

INCOME FROM CONTINUING OPERATIONS		160,846,996			67,584,673			13,642,877			5,478,989
Results of discontinued operations, net of tax		18,022,630			—			—			—

NET INCOME		178,869,626			67,584,673			13,642,877			5,478,989
Preferred dividends		969,794			—			—			—

EARNINGS AVAILABLE FOR COMMON STOCK	$	177,899,832		$	67,584,673		$	13,642,877		$	5,478,989

A-4

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING STATEMENTS OF INCOME

Year Ended December 31, 2004


	Western Resources (Bermuda), Ltd.			Westar Industries, Inc. Consolidated			Consolidating Entries			Westar Energy, Inc. Consolidated
SALES	$	—		$	—		$	(29,069,745	)	$	1,464,489,220

OPERATING EXPENSES:
Fuel and purchased power		—			—			(25,962,036	)		419,788,331
Operating and maintenance		—			(4,924,264	)		(3,107,709	)		412,002,378
Depreciation and amortization		—			—			—			169,309,516
Selling, general and administrative		65,818			957,216			(33,455	)		173,498,271

Total Operating Expenses		65,818			(3,967,048	)		(29,103,200	)		1,174,598,496

INCOME FROM OPERATIONS		(65,818	)		3,967,048			33,455			289,890,724

OTHER INCOME (EXPENSE):
Investment earnings		1,367,369			5,616,467			(163,778,342	)		16,746,482
Loss on extinguishment of debt		—			—			—			(18,839,843	)
Other income		—			(50,282	)		—			2,756,394
Other expense		—			—			—			(14,880,137	)

Total Other Income (Expense)		1,367,369			5,566,185			(163,778,342	)		(14,217,104	)

Interest expense		—			162,960			(3,950,158	)		142,150,954

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		1,301,551			9,370,273			(159,794,729	)		133,522,666
Income tax expense (benefit)		—			(1,662,767	)		13,308			33,442,577

INCOME FROM CONTINUING OPERATIONS		1,301,551			11,033,040			(159,808,037	)		100,080,089
Results of discontinued operations, net of tax		—			60,787,054			(20,147	)		78,789,537

NET INCOME		1,301,551			71,820,094			(159,828,184	)		178,869,626
Preferred dividends		—			—			—			969,794

EARNINGS AVAILABLE FOR COMMON STOCK	$	1,301,551		$	71,820,094		$	(159,828,184	)	$	177,899,832

A-5

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING STATEMENT OF RETAINED EARNINGS

DECEMBER 31, 2004


	Westar Energy, Inc.			Kansas Gas and Electric Company		WR Receivables Corporation			Westar Generating, Inc.		AV One, Inc.
BALANCE AT BEGINNING OF PERIOD	$	(102,782,026	)	$	25,094,231	$	(5,150,199	)	$	16,670,179	$	(12,553,005	)

ADD:
Net Income		178,869,626			67,584,673		13,642,877			5,478,989		—
Other		—			—		—			—		—

Total		178,869,626			67,584,673		13,642,877			5,478,989		—

DEDUCT:
Preferred stock dividends		242,452			—		—			—		—
Common stock dividends		19,786,144			75,000,000		—			—		—
Other		1,006,027			—		—			—		—

Total		21,034,623			75,000,000		—			—		—

BALANCE AT END OF PERIOD	$	55,052,977		$	17,678,904	$	8,492,678		$	22,149,168	$	(12,553,005	)

A-6

Exhibit A-1

WESTAR ENERGY, INC.

CONSOLIDATING STATEMENT OF RETAINED EARNINGS

DECEMBER 31, 2004


	Western Resources (Bermuda), Ltd.			Westar Industries, Inc. Consolidated			Consolidating Entries			Westar Energy, Inc. Consolidated
BALANCE AT BEGINNING OF PERIOD	$	11,533,922		$	(704,552,597	)	$	668,957,469		$	(102,782,026	)

ADD:
Net Income		1,301,551			71,820,094			(159,828,184	)		178,869,626
Other		—			33,932,146			(33,932,146	)		—

Total		1,301,551			105,752,240			(193,760,330	)		178,869,626

DEDUCT:
Preferred stock dividends		—			—			—			242,452
Common stock dividends		25,656,812			—			(100,656,812	)		19,786,144
Other		—			—			—			1,006,027

Total		25,656,812			—			(100,656,812	)		21,034,623

BALANCE AT END OF PERIOD	$	(12,821,339	)	$	(598,800,357	)	$	575,853,951		$	55,052,977

A-7

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004


	Westar Industries, Inc.			Westar Limited Partners, Inc.			The Wing Group Limited Company
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,910,746		$	400,000		$	—
Accounts receivable, net		102,943,566			(393,664	)		70,869
Deferred tax assets		—			204,287			—
Other		3,747			4,520			—

Total Current Assets		104,858,059			215,143			70,869

OTHER ASSETS		6,568,626			—			—

TOTAL ASSETS	$	111,426,685		$	215,143		$	70,869

LIABILITIES AND SHAREHOLDER’S EQUITY

CURRENT LIABILITIES:
Accounts payable	$	43,491		$	—		$	—
Accrued taxes		10,486,520			500			—
Other		1,096,776			—			—

Total Current Liabilities		11,626,787			500			—

LONG-TERM LIABILITIES:
Deferred income taxes		(1,269,770	)		(326,183	)		(5,472,656	)

Total Long-Term Liabilities		(1,269,770	)		(326,183	)		(5,472,656	)

COMMITMENTS AND CONTINGENCIES

SHAREHOLDER’S EQUITY:
Common stock		731,971			1,000			—
Paid-in capital		699,138,054			2,517,742			43,060,337
Retained earnings (accumulated deficit)		(598,800,357	)		(1,977,916	)		(37,516,812	)

Total Shareholder’s Equity		101,069,668			540,826			5,543,525

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	111,426,685		$	215,143		$	70,869

A-8

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2004


	Protection One International, Inc.			Consolidating Entries			Westar Industries, Inc. Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	—		$	—		$	2,310,746
Accounts receivable, net		—			—			102,620,771
Deferred tax assets		484,274			(688,561	)		—
Other		—			—			8,267

Total Current Assets		484,274			(688,561	)		104,939,784

OTHER ASSETS		—			499,985			7,068,611

TOTAL ASSETS	$	484,274		$	(188,576	)	$	112,008,395

LIABILITIES AND SHAREHOLDER’S EQUITY

CURRENT LIABILITIES:
Accounts payable	$	—		$	—		$	43,491
Accrued taxes		—			—			10,487,020
Other		—			(688,560	)		408,216

Total Current Liabilities		—			(688,560	)		10,938,727

LONG-TERM LIABILITIES:
Deferred income taxes		—			7,068,609			—

Total Long-Term Liabilities		—			7,068,609			—

COMMITMENTS AND CONTINGENCIES

SHAREHOLDER’S EQUITY:
Common stock		—			(1,000	)		731,971
Paid-in capital		79,052,696			(124,630,775	)		699,138,054
Retained earnings (accumulated deficit)		(78,568,422	)		118,063,150			(598,800,357	)

Total Shareholder’s Equity		484,274			(6,568,625	)		101,069,668

TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	484,274		$	(188,576	)	$	112,008,395

A-9

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING STATEMENTS OF INCOME

Year Ended December 31, 2004


	Westar Industries, Inc.			Westar Limited Partners, Inc.			Wing Turkey, Inc.			Wing International, Ltd.
SALES	$	—		$	—		$	—		$	—

OPERATING EXPENSES:
Operating and maintenance		(4,925,592	)		1,328			—			—
Selling, general and administrative		354,848			2,513			256,575			343,280

Total Operating Expenses		(4,570,744	)		3,841			256,575			343,280

INCOME FROM OPERATIONS		4,570,744			(3,841	)		(256,575	)		(343,280	)

OTHER INCOME (EXPENSE):
Investment earnings		3,062,118			(50,874	)		1,262,740			1,781,735
Other income		77,393			(50,282	)		—			—

Total Other Income (Expense)		3,139,511			(101,156	)		1,262,740			1,781,735

Interest expense		—			—			—			162,960

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		7,710,255			(104,997	)		1,006,165			1,275,495
Income tax expense (benefit)		(4,265,712	)		(48,267	)		352,158			—

INCOME FROM CONTINUING OPERATIONS		11,975,967			(56,730	)		654,007			1,275,495
Results of discontinued operations, net of tax		59,844,127			—			—			—

NET INCOME (LOSS)	$	71,820,094		$	(56,730	)	$	654,007		$	1,275,495

A-10

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING STATEMENTS OF INCOME

Year Ended December 31, 2004


	The Wing Group Limited Company			Protection One International, Inc.			Consolidating Entries			Westar Industries, Inc. Consolidated
SALES	$	—		$	—		$	—		$	—

OPERATING EXPENSES:
Operating and maintenance		—			—			—			(4,924,264	)
Selling, general and administrative		—			—			—			957,216

Total Operating Expenses		—			—			—			(3,967,048	)

INCOME FROM OPERATIONS		—			—			—			3,967,048

OTHER INCOME (EXPENSE):
Investment earnings		(12,664	)		—			(426,588	)		5,616,467
Other income		—			—			(77,393	)		(50,282	)

Total Other Income (Expense)		(12,664	)		—			(503,981	)		5,566,185

Interest expense		—			—			—			162,960

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(12,664	)		—			(503,981	)		9,370,273
Income tax expense (benefit)		172,504			3,127,032			(1,000,482	)		(1,662,767	)

INCOME FROM CONTINUING OPERATIONS		(185,168	)		(3,127,032	)		496,501			11,033,040
Results of discontinued operations, net of tax		—			—			942,927			60,787,054

NET INCOME (LOSS)	$	(185,168	)	$	(3,127,032	)	$	1,439,428		$	71,820,094

A-11

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING STATEMENT OF RETAINED EARNINGS

DECEMBER 31, 2004


	Westar Industries, Inc.			Westar Limited Partners, Inc.			Wing Turkey, Inc.			Wing International, Ltd.
BALANCE AT BEGINNING OF PERIOD	$	(704,552,597	)	$	(1,921,186	)	$	3,576,650		$	8,131,911

ADD:
Net Income (Loss)		71,820,094			(56,730	)		654,007			1,275,495
Other		33,932,146			—			(4,230,657	)		(9,407,406	)

Total		105,752,240			(56,730	)		(3,576,650	)		(8,131,911	)

DEDUCT:
Preferred stock dividends		—			—			—			—
Common stock dividends		—			—			—			—

Total		—			—			—			—

BALANCE AT END OF PERIOD	$	(598,800,357	)	$	(1,977,916	)	$	—		$	—

A-12

Exhibit A-2

WESTAR INDUSTRIES, INC.

CONSOLIDATING STATEMENT OF RETAINED EARNINGS

DECEMBER 31, 2004


	The Wing Group Limited Company			Protection One International, Inc.			Consolidating Entries		Westar Industries, Inc. Consolidated
BALANCE AT BEGINNING OF PERIOD	$	(37,331,644	)	$	(75,441,390	)	$	102,985,659	$	(704,552,597	)

ADD:
Net Income (Loss)		(185,168	)		(3,127,032	)		1,439,428		71,820,094
Other		—			—			13,638,063		33,932,146

Total		(185,168	)		(3,127,032	)		15,077,491		105,752,240

DEDUCT:
Preferred stock dividends		—			—			—		—
Common stock dividends		—			—			—		—

Total		—			—			—		—

BALANCE AT END OF PERIOD	$	(37,516,812	)	$	(78,568,422	)	$	118,063,150	$	(598,800,357	)

A-13

WESTAR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this report 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 653,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our consolidated financial statements in accordance with Generally Accepted Accounting Principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions and majority owned subsidiaries for which we maintain controlling interests. Common stock investments that are not majority owned are accounted for using the equity method when our investment allows us the ability to exert significant influence. Undivided interests in jointly-owned generation facilities are consolidated on a pro rata basis. All material intercompany accounts and transactions have been eliminated in consolidation.

Use of Management’s Estimates

When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, investments, valuation of our energy marketing portfolio, intangible assets, 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.

A-14

Regulatory Accounting

We currently apply accounting standards for our regulated utility operations that recognize the economic effects of rate regulation in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and, accordingly, have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent.

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent probable obligations to make refunds to customers for previous collections for costs that are not likely to be incurred in the future. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.


	As of December 31,
	2004		2003
	(In Thousands)
Amounts due from customers for future income taxes, net	$	191,597	$	207,812
Debt reacquisition costs		45,203		25,155
Deferred employee benefit costs		39,727		18,424
Deferred plant costs		27,979		28,532
2002 ice storm costs		17,774		16,369
Asset retirement obligations		77,349		70,455
KCC depreciation		22,596		14,294
Wolf Creek outage		6,467		13,645
Other regulatory assets		14,252		16,629

Total regulatory assets	$	442,944	$	411,315

Total regulatory liabilities	$	29,292	$	14,323

• Amounts due from customers for future income taxes, net: In accordance with various rate orders, we have reduced rates to reflect the tax benefits associated with certain accelerated tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce rates charged customers for deferred taxes recovered from customers at corporate tax rates higher than the current tax rates. The rate reduction will occur as the temporary differences resulting in the excess deferred tax liabilities reverse. The tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled through future rates. The net regulatory asset for these tax items is classified above as amounts due from customers for future income taxes. • Debt reacquisition costs: Includes loss on reacquired debt and refinancing costs on the LaCygne 2 generating unit lease. Debt reacquisition costs are amortized over the original term of the reacquired debt or, if refinanced, the term of the new debt. • Deferred employee benefit costs: Employee benefit costs include pension benefit obligations and post-retirement and post-employment expenses. • Deferred plant costs: Deferred plant costs under SFAS No. 90, “Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs,” related to the Wolf Creek nuclear generating facility will be recovered over the term of the plant’s operating license through 2025. • 2002 ice storm costs: We accumulated and deferred for future recovery costs related to system restoration from an ice storm that occurred in January 2002. We were authorized to accrue carrying costs on this item. Recovery of this asset will be considered during the 2005 rate review. • Asset retirement obligations: Asset retirement obligations represent amounts associated with our legal obligation to retire Wolf Creek. We recover final retirement costs through rates as provided by the Kansas Corporation Commission (KCC). We have placed amounts recovered through rates in a trust. The trust’s funds will be used to pay for the costs to retire and decommission Wolf Creek. See Note 16, “Asset Retirement Obligations,” for information regarding our Nuclear Decommissioning Trust Fund.

A-15

• KCC depreciation: Due to the change in our depreciation rates for ratemaking purposes for Wolf Creek and LaCygne 2, we record a regulatory asset for the amount that our depreciation expense exceeds our depreciation costs recovered in rates. See “—Depreciation” for additional information.

• Wolf Creek outage: Represents maintenance costs incurred in our most recent refueling outage. In accordance with regulatory treatment, this amount is amortized to expense ratably over the 18-month period after the outage.

• Other regulatory assets: This includes various regulatory assets that are relatively small in relation to the total regulatory assets balance. Other regulatory assets include property taxes, coal contract settlement costs, rate review expense, and the net removal component included in depreciation rates.

• Other regulatory liabilities: This includes various regulatory liabilities that are relatively small and includes provisions for rate refunds, property taxes, emissions allowances, savings from the sale of an office building and the net removal component included in depreciation rates. Other regulatory liabilities are included in other long-term liabilities on our consolidated balance sheets.

A return is allowed on the KCC depreciation and coal contract settlement costs.

Cash and Cash Equivalents

We consider highly liquid investments with maturities of three months or less when purchased to be cash equivalents.

Restricted Cash

Restricted cash consists of cash irrevocably deposited in trust for a prepaid capacity and transmission agreement, letters of credit, surety bonds and escrow arrangements as required by certain letters of credit, and various other deposits.

Inventories and Supplies

Inventories and supplies are stated at average cost.

Property, Plant and Equipment

Property, plant and equipment is stated at cost. For utility plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision, and an allowance for funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction projects. The AFUDC rate was 3.79% in 2004, 5.27% in 2003 and 5.95% in 2002. The cost of additions to utility plant and replacement units of property is capitalized. AFUDC capitalized was $1.8 million in 2004, $1.5 million in 2003 and $2.2 million in 2002.

Maintenance costs and replacement of minor items of property are charged to expense as incurred. Normally, when a unit of depreciable property is retired, the original cost, less salvage value, is charged to accumulated depreciation.

Depreciation

Utility plant is depreciated on the straight-line method at rates based on the estimated remaining useful lives of the assets, which are based on an average annual composite basis using group rates that approximated 2.6% during 2004, 2.5% during 2003 and 2.7% during 2002.

Effective April 1, 2002, we adopted new depreciation rates which reduced our annual depreciation expense by approximately $30.0 million.

A-16

As part of the 2001 KCC rate order, the KCC extended the estimated retirement date for Wolf Creek from 2025 to 2045, although our operating license for Wolf Creek expires in 2025. The KCC also extended the estimated retirement date for LaCygne 2 to 2032, although the term of our lease for LaCygne 2 expires in 2016. The effect of extending the retirement date was to reduce our depreciation and amortization expense recovered in customer rates. For financial statement purposes, we recognize depreciation and amortization expense based on the current operating license and the lease term. We record a regulatory asset for the difference between the KCC allowed expense and the expense recorded for financial statement purposes.

Depreciable lives of property, plant and equipment are as follows.


		Years
Fossil fuel generating facilities		6 to 68
Nuclear fuel generating facility		38 to 45
Transmission facilities		28 to 67
Distribution facilities		19 to 57
Other		5 to 55

Nuclear Fuel

Our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication is recorded as an asset in property, plant and equipment on our consolidated balance sheets at original cost and is amortized to fuel and purchased power based on the quantity of heat consumed during the generation of electricity, as measured in millions of British Thermal Units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $30.9 million at December 31, 2004 and $16.6 million at December 31, 2003. Spent fuel charged to fuel and purchased power was $19.3 million in 2004, $17.0 million in 2003 and $17.8 million in 2002.

Cash Surrender Value of Life Insurance

We recorded the following amounts related to corporate-owned life insurance policies (COLI) in other long-term assets on our consolidated balance sheets at December 31.


	2004			2003
	(In Thousands)
Cash surrender value of policies	$	967,485		$	906,118
Borrowings against policies		(891,320	)		(834,673	)

COLI, net	$	76,165		$	71,445

Income is recorded for increases in cash surrender value and net death proceeds. Interest incurred on amounts borrowed is offset against policy income. Income recognized from death proceeds is highly variable from period to period. Death benefits recognized as income on our consolidated statements of income (loss) approximated $2.0 million in 2004, $1.8 million in 2003 and $3.6 million in 2002.

Revenue Recognition – Energy Sales

We recognize revenues from retail energy sales upon delivery to the customer and include an estimate for energy delivered but unbilled. Our estimate of revenue attributable to this unbilled portion is based on the total energy available for sale measured against billed sales. At December 31, 2004, we had estimated unbilled revenue of $47.6 million.

We account for energy marketing derivative contracts under the mark-to-market method of accounting. Under this method, we recognize changes in the portfolio value as gains or losses in the period of change. Unless related to fuel, we include the net mark-to-market change in sales on our consolidated statements of income (loss). We record the resulting unrealized gains and losses as energy marketing long-term or short-term assets and liabilities on our consolidated balance sheets as appropriate. We use quoted market prices to value our energy marketing and derivative contracts when such data are available. When market prices are not readily available or determinable, we use alternative approaches, such as model pricing. Prices used to value these transactions reflect our best estimate of fair values of our trading positions. Results actually achieved from these activities could vary materially from intended results and could affect our consolidated financial results.

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Income Taxes

We use the asset and liability method of accounting for income taxes as required by SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties.

Dilutive Shares

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, 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 (ESPP). The dilutive effect of shares under the ESPP, stock-based compensation and stock options is computed using the treasury stock method.

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


	Year Ended December 31,
	2004	2003	2002
DENOMINATOR FOR BASIC AND DILUTED EARNINGS PER SHARE:
Denominator for basic earnings per share - weighted average shares	82,941,374	72,428,728	71,731,580
Effect of dilutive securities:
Employee stock purchase plan shares	17,515	113,737	11,030
Employee stock options	1,943	305	—
Restricted share awards	680,216	924,978	527,116

Denominator for diluted earnings per share - weighted average shares	83,641,048	73,467,748	72,269,726

Potentially dilutive shares not included in the denominator because they are antidilutive	217,375	217,375	232,638

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Stock Based Compensation

For purposes of the pro forma disclosures required by 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.


	2004		2003		2002
	(Dollars In Thousands, Except Per Share Amounts)
Earnings (loss) available for common stock, as reported	$	177,900	$	84,042	$	(793,400	)
Add: Stock-based compensation included in earnings (loss) available for common stock, as reported, net of related tax effects		294		46		1
Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects		757		2,615		188

Earnings (loss) available for common stock, pro forma	$	177,437	$	81,473	$	(793,587	)

Weighted average shares used for dilution		83,641,048		73,467,748		72,269,726

Earnings (loss) per share:
Basic - as reported	$	2.14	$	1.16	$	(11.06	)
Basic - pro forma	$	2.14	$	1.12	$	(11.06	)

Diluted - as reported	$	2.13	$	1.14	$	(10.98	)
Diluted - pro forma	$	2.12	$	1.11	$	(10.98	)

Segments of Business

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, Inc. (ONEOK), Protection One, Inc. 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) per share of the entire company. We no longer have a distinction between segments for utility operations and other investments.

Supplemental Cash Flow Information


	2004		2003		2002
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	127,993	$	208,174	$	218,066
Income taxes		1,162		53,625		510
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock to subsidiary (See Note 19, “Common and Preferred Stock”)		—		—		86,870
Issuance of common stock for reinvested dividends and RSUs		14,674		9,505		23,146
Assets acquired through capital leases		3,272		1,252		6,471

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Reclassifications

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

3. RATE MATTERS AND REGULATION

Rate Review Request

As a result of an earlier KCC order, we will file a request for a rate review with the KCC by May 2, 2005, based on a test year consisting of the 12 months ended December 31, 2004.

Current Status of the Debt Reduction Plan

In 2004, we reduced, by $533.4 million, the debt shown on our consolidated balance sheet with internally generated cash, the proceeds received from the sale of Protection One, Inc. (Protection One) and proceeds from an equity offering. Additionally, due to the sale of Protection One in February 2004, we reduced the long-term debt that was included in the liabilities of discontinued operations by $305.2 million.

Electric Service Reliability

On January 16, 2004, the KCC issued an order regarding electric service reliability for retail customers. The order was intended to help the KCC assess the reliability of retail electric service. Specifically, the KCC wanted to establish uniform definitions and requirements regarding service obligations, record keeping, customer notification and methods of reporting results to the KCC. On February 10, 2004, the North American Electric Reliability Council (NERC) issued reliability improvement initiatives stemming from the investigation of the August 14, 2003 blackout in portions of the northeastern United States. These initiatives will impact our operations in a number of ways, including system relay protection, vegetation management and operator training. The NERC and the ten operating regions in the United States, including the Southwest Power Pool, are working together to determine what operating policies and planning standards changes are necessary to achieve the NERC’s goals. We are unable to estimate potential compliance costs at this time, it is likely that our annual capital and maintenance expenditure requirements will increase in the future.

4. DISCONTINUED OPERATIONS — SALE OF PROTECTION ONE AND PROTECTION ONE EUROPE

In 2003, we classified our monitored security businesses as discontinued operations. We also reclassified historical periods to conform with this classification.

We sold our interest in Protection One Europe on June 30, 2003. The sale resulted in a $58.7 million reduction in our consolidated debt level from the buyer’s assumption of $48.2 million of Protection One Europe debt that was included on our consolidated financial statements and the use of $10.5 million of cash proceeds to pay down debt.

On February 17, 2004, we closed the sale of our interest in Protection One to subsidiaries of Quadrangle Capital Partners LP and Quadrangle Master Funding Ltd. (together, Quadrangle). At closing, we assigned to Quadrangle the senior credit facility between Westar Industries, Inc., Westar Energy’s wholly owned subsidiary, and Protection One, which had an outstanding balance of $215.5 million. At closing, we received proceeds of $122.2 million.

Protection One had been part of our consolidated tax group since 1997. Under the terms of a tax sharing agreement, we have reimbursed Protection One for current tax benefits used in our consolidated tax return attributable to Protection One. On November 12, 2004, we entered into a settlement agreement with Protection One and Quadrangle that, among other things, terminated a tax sharing agreement, settled Protection One’s claims with us relating to the tax sharing agreement and settled claims between Quadrangle and us relating to the sale transaction. Pursuant to the terms of the settlement agreement, Quadrangle paid us $32.5

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million in cash as additional consideration, and we settled tax sharing-related obligations to Protection One by tendering $27.1 million in Protection One 7-3/8% senior notes, including accrued interest, and paying $45.9 million in cash. Our net cash payment under the settlement agreement was $13.4 million. In addition, the settlement agreement provided that we would jointly agree to make an Internal Revenue Code (IRC) Section 338(h)(10) election. For tax purposes, an IRC Section 338(h)(10) election allows us to treat the sale of Protection One stock as a sale of the assets of Protection One.

Effective January 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 142 established new standards for accounting for goodwill. SFAS No. 142 continued to require the recognition of goodwill as an asset, but discontinued the amortization of goodwill. In addition, annual impairment tests must be performed using a fair-value based approach as opposed to an undiscounted cash flow approach required under prior standards. Upon the completion of the impairment tests as of January 1, 2002, we determined that the carrying values of goodwill at Protection One and Protection One Europe had been impaired and impairment charges were recorded as discussed below.

Another impairment test of Protection One’s goodwill and customer accounts was completed as of July 1, 2002 (the date selected for Protection One’s annual impairment test), with the independent appraisal firm providing the valuation of the estimated fair value of Protection One’s reporting units, and no impairment was indicated. Protection One’s stock price declined after regulatory orders were issued. As a result, Protection One retained the independent appraisal firm to perform an additional valuation of Protection One’s reporting units so it could perform an impairment test as of December 31, 2002, which resulted in the additional impairment charge discussed below.

SFAS No. 144 established a new approach to determining whether Protection One’s customer account asset was impaired. The approach no longer permitted the evaluation of the customer account asset for impairment based on the net undiscounted cash flow stream obtained over the remaining life of goodwill associated with the customer accounts being evaluated. Rather, the cash flow stream used under SFAS No. 144 is limited to future estimated undiscounted cash flows from assets in the asset group, which include customer accounts, the primary asset of Protection One, plus an estimated amount for the sale of the remaining assets within the asset group (including goodwill). If the undiscounted cash flow stream from the asset group is less than the combined book value of the asset group, then customer account asset carrying value must be written down to fair value, by recording an impairment.

The new rule substantially reduced the net undiscounted cash flows for customer account impairment evaluation purposes as compared to the previous accounting rules. Using these new guidelines, it was determined that there was an indication of impairment of the carrying value of the customer accounts and an impairment charge was recorded as discussed below.

To implement the new standards, an independent appraisal firm was engaged to help management estimate the fair values of Protection One’s and Protection One Europe’s goodwill and customer accounts. Based on this analysis, a charge was recorded in the first quarter of 2002 of approximately $749.3 million (net of tax benefit and minority interests), of which $555.4 million was related to goodwill and $193.9 million was related to customer accounts.

Protection One completed an additional impairment test of goodwill as of December 31, 2002 and we recorded an impairment charge of $79.7 million, net of tax benefit and minority interests, in the fourth quarter of 2002 to reflect the impairment of all remaining goodwill of Protection One’s North America segment.

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Results of discontinued operations are presented in the table below.


	Year Ended December 31,
	2004			2003			2002
	(In Thousands, Except Per Share Amounts)
Sales	$	22,466		$	306,938		$	351,499
Costs and expenses		19,937			289,900			754,656

Earnings (loss) from discontinued operations before income taxes		2,529			17,038			(403,157	)
Estimated gain (loss) on disposal		30,980			(258,979	)		(1,853	)
Income tax benefit		(45,281	)		(164,036	)		(146,910	)

Results of discontinued operations before accounting change, net of tax		78,790			(77,905	)		(258,100	)
Cumulative effect of accounting change, net of tax of $72,335		—			—			(623,717	)

Results of discontinued operations	$	78,790		$	(77,905	)	$	(881,817	)

Basic Earnings (Loss) Per Share:
Results of discontinued operations, before accounting change	$	0.95		$	(1.08	)	$	(3.60	)
Cumulative effect of accounting change, net of tax		—			—			(8.69	)

Results of discontinued operations, net of tax	$	0.95		$	(1.08	)	$	(12.29	)

Diluted Earnings (Loss) Per Share:
Results of discontinued operations, before accounting change	$	0.94		$	(1.06	)	$	(3.57	)
Cumulative effect of accounting change, net of tax		—			—			(8.63	)

Results of discontinued operations, net of tax	$	0.94		$	(1.06	)	$	(12.20	)

The major classes of assets and liabilities of the monitored services businesses were as follows.


	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

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5. ACCOUNTS RECEIVABLE AND VARIABLE INTEREST ENTITIES

Our accounts receivable on our consolidated balance sheets are comprised as follows.


	As of December 31,
	2004			2003
	(In Thousands)
Customer accounts receivable	$	97,017		$	85,712
Allowance for uncollectable accounts		(5,152	)		(5,313	)

Transferred receivables, net		91,865			80,399
Other accounts receivable		828			674
Other allowance for uncollectable accounts		(161	)		(102	)

Accounts receivable, net	$	92,532		$	80,971

Accounts Receivable Sales Program

WR Receivables Corporation, a wholly owned subsidiary, has an agreement with a financial institution whereby WR Receivables can sell an interest of up to $125.0 million in a designated pool of our qualified accounts receivable. The agreement expires in July 2005. Under the terms of the agreement, new receivables generated by us are continuously purchased by WR Receivables. The receivables sold to the financial institution are not reflected in the accounts receivable balance in the accompanying consolidated balance sheets. The amounts sold to the financial institution were $80.0 million at December 31, 2004 and 2003.

We service, administer and collect the receivables on behalf of the financial institution. Administrative expenses associated with the sale of these receivables were $2.1 million in 2004, $2.4 million in 2003 and $2.9 million in 2002. We include these expenses in other expense on our consolidated statements of income (loss).

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


	As of December 31,
	2004		2003
	(In Thousands)
Accounts receivables retained by WR Receivables, net	$	81,842	$	71,213
Accounts receivables reserved for purchaser, net		10,023		9,186

Transferred receivables, net	$	91,865	$	80,399

The following table provides gross proceeds and repayments between WR Receivables and the financial institution. We record these items on the consolidated statements of cash flows in the accounts receivable, net, line of cash flows from operating activities.


	Year Ended December 31,
	2004			2003			2002
	(In Thousands)
Proceeds from the purchaser due to the sale of receivables	$	40,000		$	—		$	30,000
Payments to the purchaser for net collection of its receivables		(40,000	)		(30,000	)		(20,000	)

Proceeds and repayments, net	$	—		$	(30,000	)	$	10,000

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Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Standards Board (FASB) issued Financial Interpretation Number (FIN) 46, “Consolidation of Variable Interest Entities,” which was subsequently revised in December 2003 with the issuance of FIN 46R. The objective of this interpretation is to provide guidance on how to identify Variable Interest Entities (VIE) and determine when the assets, liabilities, non-controlling interests and results of operations of a VIE need to be included in a company’s consolidated financial statements. A company that holds variable interests in an entity will need to consolidate the entity if the company’s interest in the VIE is such that the company will absorb a majority of the VIE’s expected losses and/or receive a majority of the entity’s expected residual returns, if they occur. FIN 46R also requires additional disclosures by primary beneficiaries and other significant variable interest holders.

On December 14, 1995, Western Resources Capital I, a wholly owned trust, issued $100.0 million of 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A. On April 16, 2004, we redeemed our entire issuance of Western Resources Capital I 7-7/8% Cumulative Quarterly Income Preferred Securities, Series A, at par. On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B. On September 22, 2003, we redeemed our entire issuance of Western Resources Capital II 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, at par.

Provisions of FIN 46R required the deconsolidation of the Western Resources Capital I trust, which resulted in the amounts previously classified as shares subject to mandatory redemption being reclassified as long-term debt, affiliate on the consolidated balance sheet.

6. FINANCIAL INSTRUMENTS, ENERGY MARKETING AND RISK MANAGEMENT

Values of Financial Instruments

The carrying values and estimated fair values of our financial instruments are as shown in the table below.


	Carrying Value				Fair Value
	As of December 31,
	2004		2003		2004		2003
	(In Thousands)
Fixed-rate debt, net of current maturities (a)	$	1,419,406	$	1,815,320	$	1,530,035	$	1,946,053

(a)	Fair value is estimated based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions.

The recorded amounts of accounts receivable and other current financial instruments approximate fair value. Cash and cash equivalents, short-term borrowings and variable-rate debt are carried at cost, which approximates fair value and are not included in the table above.

The fair value estimates are based on information available at December 31, 2004 and 2003. These fair value estimates have not been comprehensively revalued since that date and current estimates of fair value may differ significantly from the amounts above.

Derivative Instruments and Hedge Accounting

We are exposed to market risks from changes in commodity prices and interest rates that could affect our consolidated results of operations and financial condition. We manage our exposure to these market risks through our regular operating and financing activities and, when deemed appropriate, economically hedge a portion of these risks through the use of derivative financial instruments. We use the term economic hedge to mean a strategy designed to manage risks of volatility in prices or rate movements on some assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We use derivative instruments as risk management tools consistent with our business plans and prudent business practices and for energy marketing purposes.

We use derivative financial and physical instruments primarily to manage risk as it relates to changes in the prices of commodities including natural gas, oil, coal and electricity. We classify derivative instruments used to manage commodity price risk inherent in fossil fuel and electricity purchases and sales as energy marketing contracts

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on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities.

Energy Marketing Activities

We engage in both financial and physical trading to manage our commodity price risk. We trade electricity, coal, natural gas and oil. We use financial instruments, including forward contracts, options and swaps and we trade energy commodity contracts daily. We may also use economic hedging techniques to manage overall fuel expenditures. We procure physical product under forward agreements and spot market transactions.

Within the trading portfolio, we take certain positions to economically hedge a portion of physical sale or purchase contracts and we take certain positions to take advantage of market trends and conditions. We reflect changes in value on our consolidated statements of income (loss). We believe financial instruments help us manage our contractual commitments, reduce our exposure to changes in cash market prices and take advantage of selected market opportunities. We refer to these transactions as energy marketing activities.

We are involved in trading activities to reduce risk from market fluctuations, enhance system reliability and increase profits. Net open positions exist, or are established, due to the origination of new transactions and our assessment of, and response to, changing market conditions. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations.

We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce our overall credit risk.

We are also exposed to commodity price changes outside of trading activities. We use derivative contracts for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in energy trades. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

We use various fossil fuel types, including coal, natural gas and oil, to operate our plants. A significant portion of our coal requirements are purchased under long-term contracts. Due to the volatility of natural gas prices, we have increasingly operated facilities that have allowed us to use lower cost fuel types as generating unit constraints and environmental restrictions allow, primarily by using oil in our facilities that also burn natural gas.

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

Although we generally attempt to balance our physical and financial contracts in terms of quantities and contract performance, net open positions typically exist. We will at times create a net open position or allow a net open position to continue when we believe that future price movements will increase the portfolio’s value. To the extent we have open positions, we are exposed to the risk that changing market prices could have a material, adverse impact on our consolidated financial position or results of operations.

The prices we use to value price risk management activities reflect our estimate of fair values considering various factors, including closing exchange and over-the-counter quotations, time value of money and price volatility factors underlying the commitments. We adjust prices to reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions. We consider a number of risks

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and costs associated with the future contractual commitments included in our energy portfolio, including credit risks associated with the financial condition of counterparties and the time value of money. We continuously monitor the portfolio and value it daily based on present market conditions.

Hedging Activities

During the third quarter of 2001, we entered into hedging relationships to manage commodity price risk associated with future natural gas purchases. Initially, we entered into futures and swap contracts with terms extending through July 2004 to hedge price risk for a portion of our anticipated natural gas fuel requirements for our generation facilities. We designated these hedging relationships as cash flow hedges.

In 2002, due to the increased availability of our coal units and because we began burning more oil as use of oil became more economically favorable than natural gas, we did not burn our forecasted amount of natural gas. In September 2002, we determined that we had over-hedged approximately 12,000,000 MMBtu for the remaining period of the hedge. As a result of the discontinuance of this portion of the cash flow hedge, we recognized a gain of $4.0 million. In December 2003, we determined we could no longer meet the criteria to use hedge accounting for the 2004 forecasted natural gas purchases. As a result, we recognized in income a gain of $3.7 million, of which $2.8 million had previously been recognized in other comprehensive income.

Effective October 4, 2001, we entered into a $500.0 million interest rate swap agreement with a term of two years. At that time, the effect of the swap agreement was to fix the annual interest rate on a term loan at 6.18%. We settled the swap agreement for a nominal amount on September 29, 2003.

In the second quarter of 2003, we purchased a call option at a cost of $65.8 million, which locked in a settlement cost associated with a call option entered into in 1998 related to our 6.25% putable/callable notes. We settled the call option in August 2003.

7. PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment at December 31.


	2004			2003
	(In Thousands)
Electric plant in service	$	5,777,519		$	5,665,479
Electric plant acquisition adjustment		802,318			802,318
Accumulated depreciation		(2,761,781	)		(2,647,214	)

		3,818,056			3,820,583
Construction work in progress		56,910			59,570
Nuclear fuel, net		35,942			29,198

Net utility plant		3,910,908			3,909,351
Non-utility plant in service		79			149

Net property, plant and equipment	$	3,910,987		$	3,909,500

Depreciation expense on property, plant and equipment for the years ended December 31, 2004, 2003 and 2002 was as follows.


	2004		2003		2002
	(In Thousands)
Utility	$	148,933	$	147,015	$	151,538
Non-utility		—		10		58

Total depreciation expense	$	148,933	$	147,025	$	151,596

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8. JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income. Information relative to our ownership interest in these facilities at December 31, 2004 is shown in the table below.


			Our Ownership at December 31, 2004
			In-Service Dates	Investment		Accumulated Depreciation		Net MW	Ownership Percent
			(Dollars in Thousands)
LaCygne 1	(a	)	June 1973	$	191,346	$	118,168	344.0	50
Jeffrey 1	(b	)	July 1978		318,211		159,469	618.0	84
Jeffrey 2	(b	)	May 1980		311,333		142,225	617.0	84
Jeffrey 3	(b	)	May 1983		415,005		201,283	624.0	84
Jeffrey wind 1	(b	)	May 1999		874		230	0.6	84
Jeffrey wind 2	(b	)	May 1999		874		230	0.6	84
Wolf Creek	(c	)	Sept. 1985		1,409,238		590,055	548.0	47
State Line	(d	)	June 2001		108,099		15,115	200.0	40

(a) Jointly owned with Kansas City Power & Light Company (KCPL)
(b) Jointly owned with Aquila, Inc.
(c) Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.
(d) Jointly owned with Empire District Electric Company

Amounts and capacity presented above represent our share. Our share of operating expenses of the above plants, as well as such expenses for a 50% undivided interest in LaCygne 2 (representing 337 megawatt (MW) capacity) sold and leased back to KGE in 1987, are included in operating expenses on our consolidated statements of income (loss). Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

9. COMMON STOCK ISSUANCE

Westar Energy sold approximately 12.5 million shares of its common stock in 2004 for net proceeds of $245.1 million.

10. SHORT-TERM DEBT

A syndicate of banks provides us a revolving credit facility on a committed basis totaling $300.0 million. The facility is secured by KGE’s first mortgage bonds and matures on March 12, 2007. It allows us to borrow up to an aggregate limit of $300.0 million, including letters of credit up to a maximum aggregate amount of $50.0 million. At December 31, 2004, we had no outstanding borrowings and $15.3 million of letters of credit outstanding under the revolving credit facility.

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Information regarding our short-term borrowings is as follows.


	As of December 31,
	2004			2003
	(Dollars in Thousands)
Borrowings outstanding at year end:
Credit agreement and an other financing arrangement	$	—		$	1,000

Weighted average interest rate on debt outstanding at year-end, excluding fees		—			6.00	%

Weighted average short-term debt outstanding during the year	$	1,434		$	1,009

Weighted daily average interest rates during the year, excluding fees		3.50	%		6.12	%

Our interest expense on short-term debt was $1.1 million in 2004, $1.2 million in 2003 and $7.4 million in 2002.

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11. LONG-TERM DEBT

Outstanding Debt

Long-term debt outstanding at December 31 is as follows.


	2004			2003
	(In Thousands)
Westar Energy
First mortgage bond series:
7.875% due 2007	$	365,000		$	365,000
6.000% due 2014		250,000			—
8.500% due 2022		—			125,000
7.650% due 2023		—			100,000

		615,000			590,000


Pollution control bond series:
Variable due 2032, 1.95% at December 31, 2004		45,000			45,000
Variable due 2032, 2.00% at December 31, 2004		30,500			30,500
6.000% due 2033		—			58,340
5.000 % due 2033		58,340			—

		133,840			133,840

6.875% unsecured senior notes due 2004		—			184,456
9.750% unsecured senior notes due 2007		260,000			387,000
7.125% unsecured senior notes due 2009		145,078			145,078
6.80% unsecured senior notes due 2018		—			26,993
Senior secured term loan due 2005		—			114,143
Other long-term agreements		—			4,179

		405,078			861,849


KGE
First mortgage bond series:
6.500% due 2005		65,000			65,000
6.200% due 2006		100,000			100,000

		165,000			165,000

Pollution control bond series:
5.100% due 2023		13,488			13,488
Variable due 2027, 1.75% at December 31, 2004		21,940			21,940
7.000% due 2031		—			327,500
5.300% due 2031		108,600			—
5.300% due 2031		18,900			—
2.650% due 2031 and putable 2006		100,000			—
Variable due 2031, 1.92% at December 31, 2004		100,000			—
Variable due 2032, 1.67% at December 31, 2004		14,500			14,500
Variable due 2032, 1.85% at December 31, 2004		10,000			10,000

		387,428			387,428


Unamortized debt discount (a)		(1,445	)		(3,923	)
Long-term debt due within one year		(65,000	)		(185,941	)

Long-term debt, net	$	1,639,901		$	1,948,253

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

(a)	We amortize debt discount over the term of the respective issue.

The Westar Energy mortgage and the KGE mortgage each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. Additionally, Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. Therefore, we must ensure that we will be able to comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

The amount of Westar Energy’s first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is unlimited subject to certain limitations as described below. The amount of KGE’s first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented, is limited to a maximum of $2 billion, unless amended. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. At December 31, 2004, based on an assumed interest rate of

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6%, approximately $210.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. At December 31, 2004, based on an assumed interest rate of 6%, approximately $874.0 million principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage.

Westar Energy’s revolving credit facility prohibits us from increasing the amount of secured indebtedness outstanding as of March 12, 2004 by more than $300.0 million. In June 2004, Westar Energy issued $250.0 million of Westar Energy first mortgage bonds and immediately placed the funds in escrow for retirement of $225.0 million of Westar Energy first mortgage bonds, which was completed in July 2004. Therefore, at December 31, 2004, we could incur a maximum of $275.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility. Following Westar Energy’s January 18, 2005 issuance of $250.0 million of first mortgage bonds, as discussed below, we can incur a maximum of $25.0 million of additional secured debt under this provision in Westar Energy’s revolving credit facility.

During 2004, we recognized a loss of $16.1 million in connection with the redemption of our senior unsecured notes and $2.7 million in connection with the redemption of affiliate long-term debt.

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. After this transaction, we had $10.0 million outstanding under the revolving credit facility and $30.0 million available under the accounts receivable conduit facility.

Debt Covenants

Some of our debt instruments contain restrictions that require us to maintain various coverage and leverage ratios as defined in the agreements. We calculate these ratios in accordance with our credit agreements. These ratios are used solely to determine compliance with our various debt covenants. We were in compliance with these covenants at December 31, 2004.

Maturities

Maturities of long-term debt at December 31, 2004 are as follows.


Year	Principal Amount
Year	(In Thousands)
2005	$	65,000
2006		100,000
2007		625,000
2008		—
2009		145,078
Thereafter		769,823

	$	1,704,901

Our interest expense on long-term debt was $141.1 million in 2004, $223.2 million in 2003 and $227.8 million in 2002.

Affiliate Long-term Debt and Other Mandatorily Redeemable Securities

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On July 31, 1996, Western Resources Capital II, a wholly owned trust, issued $120.0 million of 8-1/2% Cumulative Quarterly Income Preferred Securities, Series B. On September 22, 2003, we redeemed our entire issuance of Western Resources Capital II
8-1/2% Cumulative Quarterly Income Preferred Securities, Series B, at par. This transaction reduced our long-term liabilities by approximately $115.7 million.

12. EMPLOYEE BENEFIT PLANS

Pension

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. Pension benefits are based on years of service and the employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Our policy is to fund pension costs accrued, subject to limitations set by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain current and retired officers. Employees hired after December 31, 2001 are covered by the same defined benefit plan with benefits derived from a cash balance account formula.

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. See Note 13, “WCNOC Employee Benefit Plans” for WCNOC benefit information.

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 decrease in the discount rates used to estimate our pension liabilities, the fair value of our pension plan assets was less than the accumulated benefit obligation at our measurement dates of December 31, 2004 and December 31, 2003. On March 29, 2004, the Federal Energy Regulatory Commission (FERC) issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to recognize as a regulatory asset the additional minimum pension liability that otherwise would have been charged to other comprehensive income (OCI). At December 31, 2004, our additional minimum pension liability adjustment was $41.8 million, offset by an intangible asset of $15.9 million and a regulatory asset of $25.9 million. At December 31, 2003, our additional minimum pension liability was $8.7 million, offset by an intangible asset of $0.9 million and OCI of $7.8 million. We accrue the cost of post-retirement benefits during the years an employee provides service. The following tables summarize the status of our pension and other post-retirement benefit plans.

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At December 31,	Pension Benefits						Post-retirement Benefits
At December 31,	2004			2003			2004			2003
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	469,651		$	433,620		$	125,324		$	124,113
Service cost		6,110			5,381			1,487			1,186
Interest cost		28,319			28,833			6,774			8,004
Plan participants’ contributions		—			—			2,695			2,242
Benefits paid		(28,880	)		(29,389	)		(12,479	)		(13,076	)
Assumption changes		11,227			27,556			4,461			7,911
Recognition of Medicare Part D		—			—			(3,807	)		—
Actuarial losses (gains)		8,050			2,710			(989	)		(5,056	)
Amendments		138			500			—			—
Curtailments, settlements and special term benefits		—			440			—			—

Benefit obligation, end of year	$	494,615		$	469,651		$	123,466		$	125,324

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	409,932		$	360,024		$	22,543		$	12,629
Adjustments		—			—			—			269
Actual return on plan assets		39,870			77,591			1,802			396
Employer contribution		—			—			17,800			19,800
Plan participants’ contributions		—			—			2,695			2,242
Benefits paid		(27,200	)		(27,683	)		(12,228	)		(12,793	)

Fair value of plan assets, end of year	$	422,602		$	409,932		$	32,612		$	22,543

Funded status	$	(72,013	)	$	(59,719	)	$	(90,854	)	$	(102,781	)
Unrecognized net loss		70,807			55,366			30,424			31,723
Unrecognized transition obligation, net		—			—			31,768			35,699
Unrecognized prior service cost		15,906			18,530			(1,398	)		(1,865	)

Prepaid (accrued) benefit costs	$	14,700		$	14,177		$	(30,060	)	$	(37,224	)

Amounts Recognized in the Balance Sheets Consist Of:
Prepaid benefit cost	$	30,597		$	28,976		$	N/A		$	N/A
Accrued benefit liability		(15,897	)		(14,799	)		(30,060	)		(37,224	)
Additional minimum liability		(41,815	)		(8,692	)		N/A			N/A
Intangible asset		15,906			923			N/A			N/A
Other comprehensive income (a)		—			7,769			N/A			N/A
Regulatory asset (a)		25,909			—			N/A			N/A

Net amount recognized	$	14,700		$	14,177		$	(30,060	)	$	(37,224	)

(a)

On March 29, 2004, FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to record the other comprehensive income related to pension benefit obligation costs as a regulatory asset.

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At December 31,	Pension Benefits						Post-retirement Benefits
At December 31,	2004			2003			2004			2003
	(Dollars in Thousands)
Accumulated Benefit Obligation	$	449,717		$	429,852			N/A			N/A
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	494,615		$	469,651			N/A			N/A
Accumulated benefit obligation		449,717			429,852			N/A			N/A
Fair value of plan assets		422,602			409,932			N/A			N/A

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	494,615		$	23,613			N/A			N/A
Accumulated benefit obligation		449,717			23,491			N/A			N/A
Fair value of plan assets		422,602			—			N/A			N/A

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation		N/A			N/A		$	123,466		$	125,324
Fair value of plan assets		N/A			N/A			32,612			22,543

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate		5.90	%		6.10	%		5.90	%		6.10	%
Compensation rate increase		3.00	%		3.10	%		3.00	%		3.10	%

We use a measurement date of December 31 for our pension and post-retirement benefit plans.

The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain (loss) subject to amortization is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan, without application of the amortization corridor described in SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”


	Pension Benefits									Post-retirement Benefits
For the Year Ended December 31,	2004			2003			2002			2004			2003			2002
	(Dollars in Thousands)
Components of Net Periodic (Benefit) Cost:
Service cost	$	6,110		$	5,381		$	6,942		$	1,487		$	1,186		$	1,248
Interest cost		28,319			28,833			28,724			6,774			8,004			7,467
Expected return on plan assets		(38,561	)		(40,513	)		(42,292	)		(1,999	)		(1,431	)		(52	)
Amortization of unrecognized transition obligation, net		—			(177	)		(251	)		3,931			3,931			3,931
Amortization of unrecognized prior service costs		2,762			3,358			3,300			(467	)		(467	)		(467	)
Amortization of loss (gain), net		2,525			(2,032	)		(5,932	)		1,172			1,612			919
Curtailments, settlements and special term benefits		—			440			12,589			—			—			—

Net periodic (benefit) cost	$	1,155		$	(4,710	)	$	3,080		$	10,898		$	12,835		$	13,046

Weighted-Average Actuarial Assumptions used to Determine Net Periodic (Benefit) Cost:
Discount rate		6.10	%		6.75	%		7.25	%		6.10	%		6.75	%		7.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		8.50	%		9.00	%		9.00	%
Compensation rate increase		3.10	%		3.75	%		4.25	%		3.10	%		3.75	%		4.25	%

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolio was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets. In selecting the discount rate, fixed income security yield rates for corporate high-grade bond yields are considered.

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In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act) became law. 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 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 $4.4 million. The subsidy also decreased the net periodic post-retirement benefit cost by approximately $0.5 million for the year ended December 31, 2004.

For measurement purposes, the assumed annual health care cost growth rates were as follows.


	At December 31,
	2004		2003
Health care cost trend rate assumed for next year	8.00	%	9.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%

Year that the rate reaches the ultimate trend rate	2008		2008

The health care cost trend rate has a significant effect on the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.


	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	113	$	(111	)
Effect on post-retirement benefit obligation		1,914		(1,878	)

The asset allocation for the pension plans and the post-retirement benefit plans at the end of 2004 and 2003, and the target allocations for 2005 and 2006, by asset category, are as shown in the following table.


	Target Allocations				Plan Assets
	2006		2005		2004		2003
Asset Category
Pension Plans:
Equity securities	65	%	65	%	68	%	68	%
Debt securities	30	%	30	%	28	%	29	%
Cash and other	5	%	5	%	4	%	3	%

Total					100	%	100	%

Post-retirement Benefit Plans:
Equity securities	65	%	40	%	35	%	32	%
Debt securities	30	%	55	%	45	%	34	%
Cash and other	5	%	5	%	20	%	34	%

Total					100	%	100	%

We manage pension and retiree welfare plan assets in accordance with the “prudent investor” guidelines contained in the Employee Retirement Income Securities Act of 1974 (ERISA). The plan’s investment strategy supports the objective of the funds, which is to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to minimize the risk of large losses. We delegate investment management to specialists in each asset class and where appropriate, provide the investment manager with specific guidelines, which include

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allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.


	Pension Benefits						Post-Retirement Benefits
	To/(From) Trust			To/(From) Company Assets			To/(From) Trust			To/(From) Company Assets
	(In Thousands)
Expected cash flows:
Expected contributions:
2005	$	—		$	1,900		$	18,600		$	300

Expected benefit payments:
2005	$	(26,700	)	$	(1,900	)	$	(8,100	)	$	(300	)
2006		(26,200	)		(2,000	)		(8,200	)		(300	)
2007		(26,000	)		(1,900	)		(8,400	)		(300	)
2008		(25,800	)		(1,800	)		(8,400	)		(300	)
2009		(25,600	)		(1,800	)		(8,400	)		(300	)
2010 – 2014		(137,000	)		(9,100	)		(42,500	)		(1,500	)

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plans are deposited with a trustee and are invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions were $3.4 million for 2004, $3.0 million for 2003 and $2.9 million for 2002.

Under our qualified employee stock purchase plan established in 1999, full-time, non-union employees purchase designated shares of our common stock at no more than a 15% discounted price. Our employees purchased 185,016 shares in 2004 at an average price of $17.20 per share. Employees purchased 403,705 shares in 2003 at an average price of $8.45 per share and employees purchased 46,432 shares at an average price of $8.45 per share in 2002. We discontinued this plan effective January 1, 2005.

Stock Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to five million shares of common stock may be granted under the LTISA Plan. At December 31, 2004, awards of 3,639,062 shares of common stock had been made under the LTISA Plan. Dividend equivalents accrue on the awarded RSUs. Dividend equivalents are the right to receive cash equal to the value of dividends paid on our common stock.

In December 2004, the 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. The provisions of the statement are effective for financial statements issued for periods that begin after June 15, 2005, which will be our third quarter beginning July 1, 2005. We will use the modified prospective transition method. Under the modified prospective method, awards that are granted, modified or settled after the date of adoption will be measured and accounted for in accordance with SFAS No. 123R. Compensation cost for awards granted prior to, but not vested as of the date SFAS No. 123R is adopted, would be based on the grant date, fair value and attributes originally used to value those awards.

We currently use RSUs for stock-based awards granted to management 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 results of operations.

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In 2004, we granted 67,051 RSUs to selected management employees and directors. In 2003, we granted 559,095 RSUs to officers, selected management employees and directors. We granted 590,585 RSUs to a broad-based group of over 800 non-union employees and directors in 2002. Each RSU represents a right to receive one share of our common stock at the end of the restricted period assuming certain criteria are met. The unearned compensation related to the grant of RSUs is shown as a separate component of shareholders’ equity. Unearned compensation is being amortized to expense over the vesting period. In addition, RSUs linked to 783,400 shares of Protection One common stock and 12,193 shares of Guardian International, Inc. preferred stock held by us were granted to certain current and former officers in 2002.

During the second quarter of 2002, active employees awarded RSUs in prior years were allowed to exchange eligible RSUs for shares of common stock. As a result, approximately 145,000 RSUs were exchanged for approximately 105,000 shares of our common stock. In addition, approximately 317,000 RSUs held by certain executive officers were exchanged for approximately 12,500 shares of Guardian International, Inc. preferred stock held by us. Compensation expense associated with this exchange totaled approximately $9.0 million for 2002. Also, in September 2002, former employees had the opportunity to convert vested RSUs into common stock. As a result, 34,433 shares of our common stock were issued in exchange for 68,865 RSUs.

Another component of the LTISA Plan is the Executive Stock for Compensation program, where in the past eligible employees were entitled to receive RSUs in lieu of current cash compensation. The Executive Stock for Compensation program was modified in 2001 to pay a portion of current compensation in the form of stock. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. At the end of the deferral period, RSUs are paid in the form of stock. Plan participants were awarded 4,422 shares of common stock for dividends in 2004, 10,009 shares in 2003, and 12,121 shares in 2002. Participants received common stock distributions of 46,544 shares in 2004, 5,101 shares in 2003 and 40,097 shares in 2002.

Stock options under the LTISA plan are as follows.


	As of December 31,
	2004				2003				2002
	Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
	(In Thousands)				(In Thousands)				(In Thousands)
Outstanding, beginning of year	226.7		$	32.92	232.6		$	32.08	552.3		$	34.02
Exercised	(1.5	)		15.31	—			—	(2.6	)		18.71
Forfeited	—			—	(5.9	)		24.99	(317.1	)		35.57

Outstanding, end of year	225.2			32.38	226.7			32.92	232.6			32.08

Stock options issued and outstanding at December 31, 2004 are as follows.


	Range of Exercise Price	Number Issued and Outstanding	Weighted- Average Contractual Life in Years	Weighted- Average Exercise Price
Options - Exercisable:
2000	$15.3125	7,783	6	$	15.31
1999	27.8125-32.125	22,900	5		29.52
1998	38.625-43.125	55,890	4		41.15
1997	30.75	94,490	3		30.75
1996	29.25	44,095	2		29.25

Total outstanding		225,158

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RSUs under the LTISA plan are as follows.


	As of December 31,
	2004				2003				2002
	Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
	(In Thousands)				(In Thousands)				(In Thousands)
Outstanding, beginning of year	1,913.7		$	16.25	1,619.9		$	18.08	1,902.9		$	22.87
Granted	60.1			20.57	547.3			12.90	584.2			13.28
Vested	(668.4	)		14.65	(251.8	)		14.60	(291.8	)		18.81
Forfeited	(7.0	)		17.72	(1.7	)		17.39	(575.4	)		28.70

Outstanding, end of year	1,298.4			17.50	1,913.7			16.25	1,619.9			18.08

RSUs issued and outstanding at December 31, 2004 are as follows.


	Range of Fair Value at Grant Date	Number Issued and Outstanding
Restricted share units:
2004	$20.45	59,225
2003	11.57 -13.95	464,731
2002	11.57 – 17.49	180,555
2001	17.67 – 19.61	196,820
2000	15.3125 –19.875	264,249
1999	27.8130 –32.125	63,783
1998	38.625	69,000

Total outstanding		1,298,363

We also issued dividend equivalents to recipients of stock options and RSUs. Recipients of RSUs receive dividend equivalents when dividends are paid on shares of company stock. The value of each dividend equivalent related to stock options is calculated by accumulating dividends that would have been paid or payable on a share of company common stock. The dividend equivalents, with respect to stock options, expire after nine years from date of grant. The weighted-average fair value at the grant-date of the dividend equivalents on stock options was $6.40 in 2004, $6.38 in 2003 and $6.35 in 2002.

13. WCNOC EMPLOYEE BENEFIT PLANS

Pension and Post-retirement Benefits

The WCNOC 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 decrease in the discount rates used to estimate pension liabilities, the fair value of WCNOC’s pension plan assets was less than the accumulated benefit obligation at the measurement dates. On March 29, 2004, the FERC issued guidance allowing an entity to recognize the amount of the minimum pension liability otherwise chargeable to other comprehensive income as a regulatory asset. On January 13, 2005, we received an accounting authority order from the KCC to recognize as a regulatory asset the additional minimum pension liability that otherwise would have been charged to other comprehensive income. At December 31, 2004, our share of WCNOC’s additional minimum pension liability adjustment was $3.1 million, offset by an intangible asset of $0.6 million and a regulatory asset of $2.5 million. At December 31, 2003, our share of WCNOC’s additional minimum pension liability was immaterial.

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As a co-owner of WCNOC, we are indirectly responsible for 47% of the liabilities and expenses associated with the WCNOC pension and post-retirement plans. We accrue our 47% of the WCNOC cost of pension and post-retirement benefits during the years an employee provides service. Our 47% share is included in the tables that follow.


	Pension Benefits						Post-retirement Benefits
At December 31,	2004			2003			2004			2003
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	49,927		$	44,519		$	5,455		$	4,857
Service cost		2,572			2,545			235			218
Interest cost		3,295			2,928			356			289
Plan participants’ contributions		—			—			147			111
Benefits paid		(849	)		(729	)		(416	)		(349	)
Actuarial losses		4,223			664			325			329

Benefit obligation, end of year	$	59,168		$	49,927		$	6,102		$	5,455

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	26,799		$	22,276		$	N/A		$	N/A
Actual return on plan assets		2,551			2,622			N/A			N/A
Employer contribution		3,810			2,459			N/A			N/A
Benefits paid		(669	)		(558	)		N/A			N/A

Fair value of plan assets, end of year	$	32,491		$	26,799		$	N/A		$	N/A

Funded status	$	(26,677	)	$	(23,128	)	$	(6,102	)	$	(5,455	)
Unrecognized net loss		15,239			11,589			2,211			2,028
Unrecognized transition obligation, net		398			455			461			519
Unrecognized prior service cost		220			252			—			—
Post-measurement date adjustments		740			441			—			—

Accrued post-retirement benefit costs	$	(10,080	)	$	(10,391	)	$	(3,430	)	$	(2,908	)

Amounts Recognized in the Balance Sheets Consist Of:
Accrued benefit liability	$	(10,080	)	$	(10,391	)	$	(3,430	)	$	(2,908	)
Additional minimum liability		(3,144	)		(66	)		N/A			N/A
Intangible asset		618			35			N/A			N/A
Other comprehensive income (a)		—			31			N/A			N/A
Regulatory asset (a)		2,526			—			N/A			N/A

Net amount recognized	$	(10,080	)	$	(10,391	)	$	(3,430	)	$	(2,908	)

(a)

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	Pension Benefits						Post-retirement Benefits
At December 31,	2004			2003			2004			2003
	(Dollars in Thousands)
Accumulated Benefit Obligation	$	46,455		$	37,037			N/A			N/A
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	59,168		$	49,927			N/A			N/A
Accumulated benefit obligation		46,455			37,037			N/A			N/A
Fair value of plan assets		32,491			26,799			N/A			N/A
Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	59,168		$	49,927			N/A			N/A
Accumulated benefit obligation		46,455			37,037			N/A			N/A
Fair value of plan assets		32,491			26,799			N/A			N/A
Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation		N/A			N/A		$	6,060		$	5,455
Fair value of plan assets		N/A			N/A			N/A			N/A
Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate		6.00	%		6.20	%		6.00	%		6.20	%
Compensation rate increase		3.00	%		3.20	%		N/A			N/A

WCNOC uses a measurement date of December 1 for the majority of its pension and post-retirement benefit plans.

The prior service cost is amortized on a straight-line basis over the average future service of the active plan participants benefiting under the plan at the time of the amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan, without application of the amortization corridor described in SFAS Nos. 87 and 106.


	Pension Benefits									Post-retirement Benefits
For the Year Ended December 31,	2004			2003			2002			2004			2003			2002
	(Dollars in Thousands)
Components of Net Periodic Cost:
Service cost	$	2,572		$	2,545		$	2,207		$	235		$	218		$	166
Interest cost		3,295			2,928			2,613			356			289			272
Expected return on plan assets		(2,780	)		(2,464	)		(2,469	)		—			—			—
Amortization of unrecognized:
Transition obligation, net		57			57			57			58			58			57
Prior service costs		31			31			27			—			—			—
Loss, net		802			603			21			141			99			73
Curtailments, settlements and special term benefits		—			—			284			—			—			—

Net periodic cost	$	3,977		$	3,700		$	2,740		$	790		$	664		$	568

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate		6.20	%		6.75	%		7.25	%		6.10	%		6.50	%		7.25	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.02	%		8.50	%		N/A			N/A
Compensation rate increase		3.20	%		Graded rates			Graded rates			N/A			N/A			N/A

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For measurement purposes, the assumed annual health care cost growth rates were as follows.


	At December 31,
	2004		2003
Health care cost trend rate assumed for next year	8.5	%	9.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2012		2012

The health care cost trend rate has a significant effect on the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.


	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	3	$	(3	)
Effect on the present value of the accumulated projected benefit obligation		46		(45	)

The asset allocation for the pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category are as shown in the following table.


		Plan Assets
Asset Category	Target Allocation for 2005	2004		2003
Pension Plans:
Equity securities	50% - 70%	65	%	66	%
Debt securities	30% - 50%	28	%	33	%
Other	0%	7	%	1	%

Total		100	%	100	%

WCNOC’s pension plan investment strategy supports the objective of the fund, which is to earn the highest possible return on plan assets consistent with a reasonable and prudent level of risk. Investments are diversified across classes, sectors and manager style to minimize the risk of large losses. WCNOC delegates investment management to specialists in each asset class and where appropriate, provides the investment manager with specific guidelines, which include allowable and/or prohibited investment types. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews.

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Expected cash flows	Pension Benefits						Post-Retirement Benefits
	To/(From) Trust			To/(From) Company Assets			To/(From) Trust		To/(From) Company Assets
	(In Thousands)
Expected contributions:
2005	$	4,700		$	200		$	N/A	$	300
Expected benefit payments:
2005	$	(800	)	$	(200	)	$	N/A	$	(300	)
2006		(900	)		(200	)		N/A		(300	)
2007		(1,100	)		(200	)		N/A		(300	)
2008		(1,400	)		(200	)		N/A		(400	)
2009		(1,600	)		(200	)		N/A		(400	)
2010 – 2014		(13,800	)		(900	)		N/A		(2,600	)

Savings Plan

WCNOC maintains a qualified 401(k) savings plan in which most of its employees participate. They match employees’ contributions in cash up to specified maximum limits. WCNOC’s contribution to the plan is deposited with a trustee and is invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. Our portion of expense associated with WCNOC’s matching contributions was $0.8 million for 2004, $0.9 million for 2003 and $0.8 million for 2002.

14. INCOME TAXES

Income tax expense (benefit) is composed of the following components at December 31.


	2004			2003			2002
	(In Thousands)
Current income taxes:
Federal	$	41,649		$	148,117		$	(41,115	)
State		(2,991	)		33,926			(5,515	)
Deferred income taxes:
Federal		(2,285	)		(78,069	)		31,014
State		1,858			(17,564	)		8,890
Investment tax credit amortization		(4,788	)		(4,642	)		(4,793	)

Total income tax expense (benefit) as reported before discontinued operations and cumulative effect of accounting change		33,443			81,768			(11,519	)
Income tax expense (benefit) from discontinued operations:
Discontinued operations		(45,281	)		(164,036	)		(146,910	)
Cumulative effect of accounting change		—			—			(72,335	)

Total income tax benefit	$	(11,838	)	$	(82,268	)	$	(230,764	)

Deferred tax assets and liabilities are reflected on our consolidated balance sheets as follows.


	December 31,
	2004		2003
	(In Thousands)
Current deferred tax assets, net	$	7,218	$	123,256
Non-current deferred tax liabilities, net		927,087		969,544

Net deferred tax liabilities	$	919,869	$	846,288

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Temporary differences related to deferred tax assets and deferred tax liabilities are summarized in the following table.


	December 31,
	2004		2003
	(In Thousands)
Deferred tax assets:
Deferred gain on sale-leaseback	$	61,241	$	66,448
General business credit carryforward (a)		27,645		27,524
Accrued liabilities		18,803		19,599
Disallowed plant costs		13,484		14,527
Long-term energy contracts		11,194		12,034
Protection One impairment		—		327,665
Capital loss carryforward (b)		230,226		—
Other		74,875		69,074

Total gross deferred tax assets		437,468		536,871
Less: Valuation allowance (b)		236,588		236,214

Deferred tax assets	$	200,880	$	300,657

Deferred tax liabilities:
Accelerated depreciation	$	659,776	$	666,315
Acquisition premium		243,165		251,163
Amounts due from customers for future income taxes, net		191,597		207,812
Other		26,211		21,655

Total deferred tax liabilities	$	1,120,749	$	1,146,945

Net deferred tax liabilities	$	919,869	$	846,288

(a) Balance represents unutilized tax credits generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These credits expire beginning 2019 through 2024. (b) We have a net capital loss of $839.6 million available to offset past and future capital gains. The capital loss can be carried back to offset 2003 capital gains (limited to the amount of 2003 taxable income). Any excess capital loss is available for carry forward through 2009. However, as we do not expect to realize any significant capital gains in the future, a valuation allowance of $230.2 million has been established. In addition, a valuation allowance of $6.4 million has been established for certain deferred tax assets related to the write-down of investments.

In accordance with various rate orders, we have reduced rates to reflect the tax benefits associated with certain accelerated tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce rates charged customers for deferred taxes recovered from customers at corporate tax rates higher than the current tax rates. The rate reduction will occur as the temporary differences resulting in the excess deferred tax liabilities reverse. The tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. This liability is classified above as amounts due from customers for future income taxes.

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The effective income tax rates set forth below are for continuing operations. The rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective tax rates and the federal statutory income tax rates are as follows.


	For the Year Ended December 31,
	2004		2003		2002
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
Effect of:
State income taxes	1.0		4.3		2.8
Amortization of investment tax credits	(3.6	)	(1.9	)	(6.2	)
Corporate-owned life insurance policies	(9.0	)	(5.0	)	(15.0	)
Accelerated depreciation flow through and amortization	5.3		2.2		6.4
Dividends received deduction	—		(1.7	)	(12.6	)
Income tax reserve adjustment	(5.3	)	—		(27.4	)
Capital loss utilization	(2.2	)	—		—
Other	3.8		0.5		2.1

Effective income tax rate	25.0	%	33.4	%	(14.9	)%

As of December 31, 2004 and 2003, we had recorded reserves for uncertain tax positions, including interest, of $49.7 million and $55.6 million, respectively. During 2004, we reduced this reserve by $5.9 million due to a re-evaluation of estimates based on expected settlements and the finalization of the sale of Protection One. Tax reserves are established for tax deductions or income positions taken in prior income tax 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 deductions or income positions are currently under audit or will likely be audited. The timing of the resolution of these audits is uncertain. If the positions taken on the 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 plus interest. We also have a tax reserve of $4.3 million (after-tax) for property and sales tax assessments by various state and local taxing authorities.

15. COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and construction program, we have purchase orders and contracts, excluding fuel, which is discussed below under “— Fuel Commitments,” that have an unexpended balance of approximately $159.4 million at December 31, 2004, of which $34.6 million has been committed. The $34.6 million commitment relates to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments at December 31, 2004 was as follows.


	Committed Amount
	(In Thousands)
2005	$	28,601
2006		3,668
2007		2,343

	$	34,612

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Clean Air Act

Generally, we must comply with the Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on major pollutants, including sulfur dioxide (SO2), particulate matter and nitrogen oxides (NOx). In addition, we must comply with the provisions of the Clean Air Act Amendments of 1990 that require a two-phase reduction in some emissions. We have installed continuous monitoring and reporting equipment in order to meet the acid rain requirements. We have not had to make any material capital expenditures to meet Phase II SO2 and NOx requirements.

EPA New Source Review

The Environmental Protection Agency (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 has informed us that it has referred this matter to the Department of Justice (DOJ) for the DOJ to consider whether to pursue an enforcement action in federal district court. We believe that costs related to updating or installing emissions controls would qualify for recovery through rates. If we were to reach a settlement with the EPA, we may be assessed a penalty. The penalty could be material and may not be recovered in rates.

Manufactured Gas Sites

We have been associated with a number of former manufactured gas sites located in Kansas and Missouri that may contain coal tar and other potentially harmful materials.

We and the Kansas Department of Health and Environment (KDHE) entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and remediate, if necessary, these sites. Through December 31, 2004, the costs incurred for preliminary site investigation and risk assessment have been minimal. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the Kansas sites, our liability for twelve of the Kansas sites is limited. Of those twelve sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in 2012. We have sole responsibility for remediation with respect to three Kansas sites. With respect to two of those sites, we are currently either conducting or completing remediation activities and, with respect to the third site, we will begin investigation activities in the near future.

Our liability for our former manufactured gas sites in Missouri is limited by an environmental indemnity agreement with Southern Union Company, which bought all of the Missouri manufactured gas sites. According to the terms of the agreement, our future liability for these sites is capped at $7.5 million and terminates in 2009.

Solid Waste Landfills

We operate solid waste landfills at Jeffrey, Lawrence and Tecumseh Energy Centers for the single purpose of disposing of coal combustion waste material. Additionally, there is one retired landfill at each of the Lawrence and Neosho Energy Centers. All landfills are permitted by the KDHE. The operating landfill at Lawrence Energy Center is projected to be full by late 2007 or early 2008 requiring us to permit and construct a new landfill at this site. We began the process of obtaining this permit in late 2003. We will continue to work with the appropriate regulatory agencies to ensure that the new landfill and expansion of the existing landfill will meet the operating requirements of the Lawrence Energy Center.

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Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that funds required for nuclear decommissioning will be accumulated prior to the termination of the license of the related nuclear power plant.

We expense nuclear decommissioning costs over the expected life of Wolf Creek. The amount we expense is based on an estimate of nuclear decommissioning costs that we will incur upon retirement of the plant. Nuclear decommissioning costs that are recovered in rates are deposited in an external trust fund. In 2004, we expensed approximately $3.9 million for nuclear decommissioning. We record our investment in the nuclear decommissioning fund at fair value. Fair value approximated $91.1 million at December 31, 2004 and $80.1 million at December 31, 2003.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the nuclear decommissioning study, the current-year funding and future funding. Phase two is the filing of a “funding schedule” by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount for the pro rata share of the plant.

We filed an updated nuclear decommissioning and dismantlement cost estimate with the KCC on August 30, 2002. Estimated costs outlined by this study were developed to decommission Wolf Creek following a shutdown. The analyses relied on site-specific, technical information, updated to reflect current plant conditions and operating assumptions. Based on this study, our share of Wolf Creek’s nuclear decommissioning costs, under the immediate dismantlement method, is estimated to be approximately $220.0 million in 2002 dollars. These costs include decontamination, dismantling and site restoration and are not inflated, escalated, or discounted over the period of expenditure. The actual nuclear decommissioning costs may vary from the estimates because of changes in technology and changes in costs for labor, materials and equipment.

The KCC issued an order on April 16, 2003 approving the August 2002 nuclear decommissioning study for Wolf Creek. On June 2, 2003, we filed a funding schedule with the KCC to reflect the KCC’s April 16, 2003 order. On October 10, 2003, the KCC approved the funding schedule as filed without any change to our funding obligation.

We charge nuclear decommissioning costs to operating expense in accordance with the July 25, 2001 KCC rate order as modified by the KCC’s approval of the funding schedule in the KCC’s October 13, 2003 order. Electric rates charged to customers provide for recovery of these nuclear decommissioning costs over the life of Wolf Creek, which, as determined by the KCC for purposes of the funding schedule, will be through 2045. The NRC requires that funds to meet its nuclear decommissioning funding assurance requirement be in our nuclear decommissioning fund by the time our license expires in 2025. We believe that the KCC approved funding level will be sufficient to meet the NRC minimum financial assurance requirement. However, our consolidated results of operations would be materially adversely affected if we are not allowed to recover the full amount of the funding requirement.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. As required by federal law, the WCNOC co-owners entered into a standard contract with the DOE in 1984 in which the DOE promised to begin accepting from commercial nuclear power plants their used nuclear fuel for disposal beginning in early 1998. In return, Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. The fee is one-tenth of a cent for each kilowatt-hour of net nuclear generation produced. We include these disposal costs in operating expenses.

A permanent disposal site will not be available for the nuclear industry until 2012 or later. Under current DOE policy, once a permanent site is available, the DOE will accept spent nuclear fuel on a priority basis. The owners of the oldest spent fuel will be given the highest priority. As a result, disposal services for Wolf Creek will not be available prior to 2018. Wolf Creek has on-site temporary storage for spent nuclear fuel. In early 2000, Wolf Creek completed replacement of spent fuel storage racks to increase its on-site storage capacity for all spent fuel expected to be generated by Wolf Creek through the end of its licensed life in 2025.

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In 2002, the Yucca Mountain site in Nevada was approved for the development of a nuclear waste repository for the disposal of spent nuclear fuel and high level nuclear waste from the nation’s defense activities. This action allows the DOE to apply to the NRC to license the project. The DOE expects that this facility will open in 2012. However, the opening of the Yucca Mountain site has been delayed many times and could be delayed further due to litigation and other issues related to the site as a permanent repository for spent nuclear fuel.

Nuclear Insurance

We maintain nuclear insurance for Wolf Creek in four areas: liability, worker radiation, property and accidental outage. These policies contain certain industry standard exclusions, including, but not limited to, ordinary wear and tear and war. Both the nuclear liability and property insurance programs subscribed to by members of the nuclear power generating industry include industry aggregate limits for non-certified acts, as defined by the Terrorism Risk Insurance Act, of terrorism-related losses, including replacement power costs. An industry aggregate limit of $300.0 million exists for liability claims, regardless of the number of non-certified acts affecting Wolf Creek or any other nuclear energy liability policy or the number of policies in place. An industry aggregate limit of $3.24 billion plus any reinsurance recoverable by Nuclear Electric Insurance Limited (NEIL), our insurance provider, exists for property claims, including accidental outage power costs for acts of terrorism affecting Wolf Creek or any other nuclear energy facility property policy within twelve months from the date of the first act. These limits are the maximum amount to be paid to members who sustain losses or damages from these types of terrorist acts. For certified acts of terrorism, the individual policy limits apply. In addition, industry-wide retrospective assessment programs (discussed below) can apply once these insurance programs have been exhausted.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, we are required to insure against public liability claims resulting from nuclear incidents to the full limit of public liability, which is currently approximately $10.8 billion. This limit of liability consists of the maximum available commercial insurance of $300.0 million, and the remaining $10.5 billion is provided through mandatory participation in an industry-wide retrospective assessment program. Under this retrospective assessment program, we can be assessed up to $100.6 million per incident at any commercial reactor in the country, payable at no more than $10.0 million per incident per year. This assessment is subject to an inflation adjustment based on the Consumer Price Index and applicable premium taxes. This assessment also applies in excess of our worker radiation claims insurance. In addition, Congress could impose additional revenue-raising measures to pay claims. If the $10.8 billion liability limitation is insufficient, Congress will consider taking whatever action is necessary to compensate the public for valid claims.

The Price-Anderson Act expired in August 2002 but was extended until December 31, 2003 for Licensees. Licensees such as Wolf Creek continue to be grandfathered under the Act. The current version of a comprehensive energy bill expected to be adopted in 2005 by Congress contains provisions that would amend Federal Law (the “Price-Anderson Act”) addressing public liability from nuclear energy hazards in ways that would increase the annual limit on retrospective assessments from $10.0 million to $15.0 million per reactor per incident.

Nuclear Property Insurance

The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion (our share is $1.3 billion). This insurance is provided by NEIL. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or decontamination expenses or, if certain requirements are met, including nuclear decommissioning the plant, toward a shortfall in the nuclear decommissioning trust fund.

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Accidental Nuclear Outage Insurance

The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $26.0 million (our share is $12.2 million).

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable through rates, would have a material adverse effect on our consolidated financial condition and results of operations.

Fuel Commitments

To supply a portion of the fuel requirements for our generating plants, we have entered into various commitments to obtain nuclear fuel and coal. Some of these contracts contain provisions for price escalation and minimum purchase commitments. At December 31, 2004, our share of WCNOC’s nuclear fuel commitments were approximately $13.5 million for uranium concentrates expiring in 2007, $1.7 million for conversion expiring in 2007, $8.6 million for enrichment expiring at various times through 2006 and $52.4 million for fabrication through 2024.

At December 31, 2004, our coal and coal transportation contract commitments in 2004 dollars under the remaining terms of the contracts were approximately $1.5 billion. The largest contract expires in 2020, with the remaining contracts expiring at various times through 2013.

At December 31, 2004, our natural gas transportation commitments in 2004 dollars under the remaining terms of the contracts were approximately $43.5 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2010, except for one contract that expires in 2016.

Energy Act

As part of the 1992 Energy Policy Act, a special assessment is being collected from utilities for a uranium enrichment decontamination and nuclear decommissioning fund. Our portion of the assessment, including carrying costs, for Wolf Creek is approximately $11.1 million, adjusted for inflation. To date, we have paid approximately $9.7 million, with the estimated remainder payable over the next two years. We recover such costs from prices we charge our customers.

16. ASSET RETIREMENT OBLIGATIONS

In January 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires recognition of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of an asset retirement obligation is capitalized and depreciated over the remaining life of the asset. Any income effects are offset by regulatory accounting pursuant to SFAS No. 71.

Legal Liability - Wolf Creek

On January 1, 2003, we recognized the liability for our 47% share of the estimated cost to decommission Wolf Creek. SFAS No. 143 requires the recognition of the present value of the asset retirement obligation we incurred at the time Wolf Creek was placed into service in 1985. On January 1, 2003, we recorded an asset retirement obligation of $74.7 million. In addition, we increased our property and equipment balance, net of accumulated depreciation, by $10.7 million. We also established a regulatory asset for $64.0 million, which represents the accretion of the liability since 1985 and the increased depreciation expense associated with the increase in plant. The asset retirement obligation is included on our consolidated balance sheets in other long-term liabilities. Currently, we recover costs to retire Wolf Creek through rates as provided by the KCC.

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The following table is a reconciliation of the legal asset retirement obligation related to the nuclear decommissioning of WCNOC, which is included on our consolidated balance sheets in other long-term liabilities.


	As of December 31, 2004
	(In Thousands)
Beginning asset retirement obligation	$	80,695
Accretion expense		6,423

Ending asset retirement obligation	$	87,118

Non-legal Liability - Cost of Removal

We have recovered amounts in rates to provide for recovery of the probable costs of removing utility plant assets, but which do not represent legal retirement obligations. At December 31, 2004, Westar Energy had $1.3 million in removal costs classified as a regulatory asset and KGE had $2.6 million in removal costs classified as a regulatory liability. At December 31, 2003, we had $6.6 million in removal costs classified as a regulatory asset. The net amount related to non-legal retirement costs can fluctuate based on amounts related to removal costs recovered compared to removal costs incurred.

17. LEGAL PROCEEDINGS

We and certain of our present and former officers 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. 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 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. The stay was subsequently extended to March 18, 2005. 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 reviews filed with the KCC in 2000, the compensation of and benefits provided to our senior management, energy marketing transactions with Cleco Corporation 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 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. The stay was extended to February 8, 2005. 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

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previously filed motions to dismiss and set a scheduling conference on March 8, 2005 to address 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. 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 H. Carter, Arthur B. Krause and Michael F. Morrissey. On August 26, 2004, the court issued an order granting a joint motion of all parties requesting a stay of the lawsuit until December 7, 2004, pending efforts to settle the lawsuit through mediation. The stay was subsequently extended to March 18, 2005. 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 scheduled to begin May 9, 2005, of 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 Notes 3, 15, 18 and 20 for discussion of KCC regulatory proceedings, alleged violations of the Clean Air Act, an investigation by the United States Attorney’s Office, an inquiry by the Securities and Exchange Commission (SEC), an investigation by FERC and potential liabilities to Mr. Wittig and Mr. Lake.

18. ONGOING INVESTIGATIONS

Grand Jury Subpoena

On September 17, 2002, we were served with a federal grand jury subpoena by the United States Attorney’s Office in Topeka, Kansas, requesting information concerning the use of aircraft and our annual shareholder meetings. Since that date, the United States Attorney’s Office has served additional subpoenas on us and certain of our employees requesting further information concerning the use of our aircraft; executive compensation arrangements with Mr. Wittig, Mr. Lake and other former and present officers; the proposed rights offering of Westar Industries stock that was abandoned; and the company in general. We are providing information in response to these requests and we are cooperating fully in the investigation. We have not been informed that we are a target of the investigation. On December 4, 2003, Mr. Wittig and Mr. Lake were indicted by the federal grand jury on conspiracy, fraud and other criminal charges related to their actions while serving as our officers. The trial on these charges was held in 2004 and ended with a mistrial. A new trial is scheduled to begin on May 9, 2005. We are unable to predict the ultimate outcome of the investigation or its impact on us.

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Securities and Exchange Commission Inquiry

On November 1, 2002, the SEC notified us that it would be conducting an inquiry into the matters involved in the restatement of our first and second quarter 2002 financial statements. Our counsel has communicated with the SEC about these and other matters within the scope of the grand jury investigation, including disclosures in our proxy statements concerning personal aircraft use by former officers and the payment of a bonus to Mr. Wittig in 2002. We are unable to predict the ultimate outcome of the inquiry or its impact on us.

FERC Subpoena

On December 16, 2002, we received a subpoena from FERC seeking details on power trades with Cleco Corporation and its affiliates, documents concerning power transactions between our system and our marketing operations and information on power trades in which we or other trading companies acted as intermediaries. We have provided information to FERC in response to the original subpoena, subsequent requests submitted through our counsel and additional subpoenas received July 28, 2003 and October 27, 2003 seeking information about compliance with FERC codes of conduct applicable to generation and transmission activities. We believe that our participation in these transactions and the conduct of our generation and transmission operations did not violate FERC rules and regulations. However, we are unable to predict the ultimate outcome of the investigation.

Department of Labor Investigation

On February 1, 2005, we received a subpoena from the Department of Labor seeking documents related to our Employees’

401(k) Savings Plan and our defined benefit pension plan. At this time, we do not know the specific purpose of the investigation and we are unable to predict the ultimate outcome of the investigation or its impact on us. See Note 17, “Legal Proceedings,” for discussion of a class action lawsuit brought on behalf of participants in our Employees’ 401(k) Savings Plan.

19. COMMON AND PREFERRED STOCK

Westar Energy’s articles of incorporation, as amended, provide for 150,000,000 authorized shares of common stock. At December 31, 2004, we had 86,029,721 shares issued and outstanding.

Westar Energy has a direct stock purchase plan (DSPP). Shares sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2004, a total of 1,318,079 shares were issued by Westar Energy for the DSPP, the employee stock purchase plan and other stock based plans operated under the 1996 Long-Term Incentive and Share Award Plan. At December 31, 2004, a total of 5,412,096 shares were available under the DSPP registration statement.

Treasury Stock

At December 31, 2004, Westar Energy did not have any treasury stock. At December 31, 2003, Westar Energy had a treasury stock balance of 203,575 shares.

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Preferred Stock Not Subject to Mandatory Redemption

Westar Energy’s cumulative preferred stock is redeemable in whole or in part on 30 to 60 days’ notice at our option. The table below shows our redemption amount for all series of preferred stock not subject to mandatory redemption at December 31, 2004.


Rate	Shares	Principal Outstanding		Call Price		Premium		Total Cost to Redeem
	(Dollars in Thousands)
4.500%	121,613	$	12,161	108.00	%	$	973	$	13,134
4.250%	54,970		5,497	101.50	%		82		5,579
5.000%	37,780		3,778	102.00	%		76		3,854

		$	21,436			$	1,131	$	22,567

The provisions of Westar Energy’s articles of incorporation, as amended, contain restrictions on the payment of dividends or the making of other distributions on our common stock while any preferred shares remain outstanding unless certain capitalization ratios and other conditions are met. If the ratio of the capital represented by our preference stock and common stock (together, Subordinated Stock), including premiums on our capital stock and its surplus accounts, to its total capital and its surplus accounts at the end of the second month immediately preceding the date of the proposed payment of dividends, adjusted to reflect the proposed payment (Capitalization Ratio), will be less than 20%, then the payment of the dividends on Subordinated Stock shall not exceed 50% of net income available for dividends for the 12-month period ending with and including the second month immediately preceding the date of the proposed payment. If the Capitalization Ratio is 20% or more but less than 25%, then the payment of dividends on the Subordinated Stock, including the proposed payment, shall not exceed 75% of its net income available for dividends for such 12-month period. Except to the extent permitted above, no payment or other distribution may be made that would reduce the Capitalization Ratio to less than 25%. The Capitalization Ratio is determined based on the unconsolidated balance sheet for Westar Energy. At December 31, 2004, the Capitalization Ratio was greater than 25%.

So long as there are any outstanding shares of Westar Energy preferred stock, Westar Energy shall not without the consent of a majority of the shares of preferred stock or if more than one-third of the outstanding shares of preferred stock vote negatively and without the consent of a percentage of any and all classes required by law and Westar Energy’s articles of incorporation, declare or pay any dividends (other than stock dividends or dividends applied by the recipient to the purchase of additional shares) or make any other distribution upon Subordinated Stock unless, immediately after such distribution or payment the sum of Westar Energy’s capital represented by the outstanding Subordinated Stock and our earned and any capital surplus shall not be less than $10.5 million plus an amount equal to twice the annual dividend requirement on all the then outstanding shares of preferred stock.

20. POTENTIAL LIABILITIES TO DAVID C. WITTIG AND DOUGLAS T. LAKE

David C. Wittig, our former chairman of the board, president and chief executive officer, resigned from all of his positions with us and our affiliates on November 22, 2002. On May 7, 2003, our board of directors determined that the employment of Mr. Wittig was terminated as of November 22, 2002 for cause. Douglas T. Lake, our former executive vice president, chief strategic officer and member of the board, was placed on administrative leave from all of his positions with us and our affiliates on December 6, 2002. On June 12, 2003, our board of directors terminated the employment of Mr. Lake for cause.

On June 13, 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against Mr. Wittig and Mr. Lake arising out of their previous employment with us. Among other things, we are seeking to recover compensation and benefits previously paid to Mr. Wittig and Mr. Lake and to avoid compensation and other benefits Mr. Wittig and Mr. Lake claim to be owed to them as a result of their previous employment with us. We are unable to predict the outcome of the arbitration.

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At December 31, 2004, we had accrued liabilities totaling approximately $57.8 million for compensation not yet paid to Mr. Wittig and Mr. Lake under various plans. The compensation includes RSU awards, deferred vested shares, deferred RSU awards, deferred vested stock for compensation, executive salary continuation plan benefits and, in the case of Mr. Wittig, benefits arising from a split dollar life insurance agreement. The amount of our obligation to Mr. Wittig related to a split dollar life insurance agreement is subject to adjustment at the end of each quarter based on the total return to our shareholders from the date of that agreement. The total return considers the change in stock price and accumulated dividends. These compensation-related accruals are included in long-term liabilities on the consolidated balance sheets with a portion recorded as a component of paid in capital. The amount accrued will increase annually as it relates to future dividends on deferred RSU awards and increases in amounts that may be due under the executive salary continuation plan.

In addition, we accrued $4.2 million at December 31, 2004 for legal fees and expenses incurred by Mr. Wittig and Mr. Lake that are recorded in accounts payable on our consolidated balance sheets. 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 17, “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.

In addition to these amounts, we could also be obligated to make payments to Mr. Wittig and Mr. Lake pursuant to the executive salary continuation plan. Assuming an expected payout period of 35 years, the aggregate nominal amount of these payments would be approximately $16.6 million for Mr. Wittig and $8.3 million for Mr. Lake.

21. REDEMPTION OF GUARDIAN INTERNATIONAL PREFERRED STOCK

On July 9, 2004, Guardian International, Inc. (Guardian) redeemed 8,397 shares of Guardian Series C preferred stock held of record by us. The redemption price was $8.6 million, representing the par value of $1,000 per share, or $8.4 million, plus $0.2 million in accrued dividends through the date of redemption and the redemption premium. In 2002, we granted certain current and former officers 540 RSUs linked to these securities. In 2002, we also transferred beneficial ownership of 4,714 shares of Guardian Series C preferred stock to Mr. Wittig and Mr. Lake in exchange for other securities. The ownership of these shares and related dividends is disputed and is the subject of the arbitration proceeding with Mr. Wittig and Mr. Lake discussed above in Note 17, “Legal Proceedings.” We recorded an approximate $0.6 million increase in the balance of our potential liability to Mr. Wittig and Mr. Lake in the third quarter to reflect the difference between the carrying value of the 4,714 shares claimed by Mr. Wittig and Mr. Lake and the redemption amount.

22. MARKETABLE SECURITIES

On January 1, 2003, we classified our investment in ONEOK as an available-for-sale security. During 2003, we sold our investment in ONEOK and recorded a pre-tax gain of $99.3 million. The following table summarizes our marketable security sales for the years ended December 31, 2004, 2003 and 2002.


	Marketable Security Sales
	2004		2003		2002
	(In Thousands)
Sales proceeds	$	—	$	801,841	$	—
Realized gains		—		99,327		—

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23. LEASES

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates ranging from 1 to 15 years. We have the right at the expiration of the basic lease terms to renew several leases, including the LaCygne 2 lease, static var equipment lease, and several railcar leases. We also have the right to purchase the equipment or assets at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the equipment if certain notification requirements are met.

In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term. The rental expense associated with the LaCygne 2 operating lease includes an offset for the amortization of the deferred gain on the sale-leaseback. The rental expense and estimated commitments are as follows for the LaCygne 2 lease and other operating leases.


Year Ended December 31,	LaCygne 2 Lease (a)		Total Operating Leases
	(In Thousands)
Rental expense:
2002	$	28,895	$	46,312
2003		28,895		42,495
2004		28,895		38,793

Future commitments:
2005	$	38,013	$	49,422
2006		42,287		53,239
2007		78,268		86,802
2008		12,609		20,343
2009		42,287		48,802
Thereafter		289,154		355,290

Total future commitments	$	502,618	$	613,898

(a) The LaCygne 2 lease amounts are included in the total operating leases column.

In 1987, KGE sold and leased back its 50% undivided interest in the LaCygne 2 generating unit. The LaCygne 2 lease has an initial term of 29 years, with various options to renew the lease or repurchase the 50% undivided interest. KGE remains responsible for its share of operating and maintenance costs and other related operating costs of LaCygne 2. The lease is an operating lease for financial reporting purposes. We recognized a gain on the sale, which was deferred and is being amortized over the lease term. The increase in payments in 2006 and 2007 represents a change in accordance with the terms of the lease from the lease payments being made in arrears to the lease payments being made in advance and are included on a straight-line basis over the minimum lease term when determining lease expense.

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Capital Leases

Capital leases are identified based on the requirements set forth in SFAS No. 13, “Accounting for Leases.” For both vehicles and computer equipment, new leases are signed each month based on the terms of the master lease agreement. The lease term for vehicles is from 5 to 14 years depending on the type of vehicle. The computer equipment has either a 2- or 3-year term. Assets recorded under capital leases are listed below.


	December 31,
	2004			2003
	(In Thousands)
Vehicles	$	35,769		$	40,018
Computer equipment and software		2,145			1,118
Accumulated amortization		(17,848	)		(18,543	)

	$	20,066		$	22,593

Capital lease payments are currently treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases at December 31, 2004 are listed below.


Year Ended December 31,	Total Capital Leases
	(In Thousands)
2005	$	5,267
2006		4,545
2007		4,024
2008		3,284
2009		2,619
Thereafter		4,462

		24,201
Amounts representing imputed interest		(4,135	)

Present value of net minimum lease payments under capital leases	$	20,066

24. RELATED PARTY TRANSACTIONS — ONEOK Shared Services Agreement

We and ONEOK had shared services agreements in which we provided and billed one another for facilities, utility field work, mobile communications, information technology, customer support, meter reading and bill processing. Payments for these services were based on various hourly charges, negotiated fees and out-of-pocket expenses.


	2004		2003		2002
	(In Thousands)
Charges to ONEOK	$	7,213	$	8,312	$	8,357

Charges from ONEOK		2,735		3,190		3,324

ONEOK terminated portions of this shared services agreement in September 2004, including 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.

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25. WORK FORCE REDUCTIONS – 2002 Voluntary Separation

During 2002, we reduced our utility work force by approximately 400 employees through a voluntary separation program. We have replaced and may continue to replace some of these employees. Below is a schedule of severance payments incurred related to this workforce reduction.


	Year Ended December 31, 2002
	(In Thousands)
Balance at January 1	$	—
Additions		19,496
Payments		(19,496	)

Balance at December 31	$	—

Any work force reductions since the completion of the 2002 voluntary separation have been in the normal course of operations.

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26. QUARTERLY RESULTS (UNAUDITED)

Our electric business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations. In addition, our net results of discontinued operations varied between comparable quarters. In the first quarter of 2003, we classified our monitored security business as discontinued operations requiring the recognition of certain tax benefits resulting in net income from discontinued operations of $103.8 million. In the third quarter of 2003, we wrote down our monitored security business to our estimate of realizable value resulting in a net loss of $161.7 million. In the fourth quarter of 2004, we recognized income from discontinued operations of $71.9 million, which reflects the results of the final settlement of all issues related to the sale of our monitored security business.


	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)
2004
Sales	$	340,263	$	358,430	$	421,489	$	344,307
Income from continuing operations		8,791		13,979		60,369		16,941
Results of discontinued operations, net of tax		6,888		—		—		71,902
Net income		15,679		13,979		60,369		88,843
Earnings available for common stock	$	15,437	$	13,737	$	60,127	$	88,599

Per Share Data (a):

Basic:

Earnings available from continuing operations	$	0.12	$	0.16	$	0.70	$	0.19
Discontinued operations, net of tax		0.09		—		—		0.84

Earnings available	$	0.21	$	0.16	$	0.70	$	1.03

Diluted:

Earnings available from continuing operations	$	0.12	$	0.16	$	0.69	$	0.19
Discontinued operations, net of tax		0.09		—		—		0.83

Earnings available	$	0.21	$	0.16	$	0.69	$	1.02

Cash dividend declared per common share	$	0.19	$	0.19	$	0.19	$	0.23

Market price per common share:
High	$	21.00	$	21.47	$	21.11	$	22.92
Low	$	18.06	$	18.24	$	19.58	$	20.05
(a) Earnings (loss) per share is computed independently for each of the periods presented. The sum of the earnings (loss) per share amounts for the quarters may not equal the total for the year.

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	First		Second		Third			Fourth
	(In Thousands, Except Per Share Amounts)
2003
Sales	$	345,434	$	345,885	$	438,167		$	331,657
Income from continuing operations		20,102		21,807		80,584			40,422
Results of discontinued operations, net of tax		103,822		6,378		(161,651	)		(26,454	)
Net income (loss)		123,924		28,185		(81,067	)		13,968
Earnings (loss) available for common stock	$	123,697	$	27,943	$	(81,283	)	$	13,686

Per Share Data (a):

Basic:

Earnings available from continuing operations	$	0.28	$	0.30	$	1.11		$	0.56
Discontinued operations, net of tax		1.44		0.09		(2.23	)		(0.37	)

Earnings (loss) available	$	1.72	$	0.39	$	(1.12	)	$	0.19

Diluted:

Earnings available from continuing operations	$	0.27	$	0.30	$	1.09		$	0.54
Discontinued operations, net of tax		1.44		0.08		(2.20	)		(0.35	)

Earnings (loss) available	$	1.71	$	0.38	$	(1.11	)	$	0.19

Cash dividend declared per common share	$	0.19	$	0.19	$	0.19		$	0.19

Market price per common share:
High	$	13.04	$	17.09	$	18.65		$	20.49
Low	$	9.76	$	12.15	$	15.45		$	18.40
(a) Earnings (loss) per share is computed independently for each of the periods presented. The sum of the earnings (loss) per share amounts for the quarters may not equal the total for the year.

27. SUBSEQUENT EVENT – Ice Storm

On January 4 and 5, 2005, substantially all of our service territory experienced a severe ice storm. The storm interrupted electric service in a large portion of our service territory and damaged a significant portion of our electric distribution system. We estimate that we will incur $38.0 million to $42.0 million of system restoration costs. Of this amount, we expect $6.0 million to $8.0 million to be accounted for as capital expenditures and we expect the balance related to maintenance expenditures to be accounted for as a regulatory asset. On February 3, 2005, we filed an application for an accounting authority order with the KCC requesting that we be allowed to accumulate and defer for future recovery maintenance costs related to system restoration. We can provide no assurance that the KCC will approve our application, however, in the past the KCC has approved similar requests.

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EXHIBIT B

An organizational chart showing the relationship of each EWG to associate companies in the holding company system.

LOGO

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