Edgar Filing: WESTAR ENERGY INC /KS

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

Kansas

48-0290150

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

818 South Kansas Avenue, Topeka, Kansas 66612 (785) 575-6300

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x

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


Common Stock, par value $5.00 per share		87,334,624 shares
(Class)		(Outstanding at October 25, 2006)

TABLE OF CONTENTS


		Page
PART I. Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited)

	Consolidated Balance Sheets	5

	Consolidated Statements of Income	6-7

	Consolidated Statements of Comprehensive Income	8

	Consolidated Statements of Cash Flows	9

	Notes to Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35

Item 4.	Controls and Procedures	35

PART II. Other Information

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3.	Defaults Upon Senior Securities	36

Item 4.	Submission of Matters to a Vote of Security Holders	36

Item 5.	Other Information	36

Item 6.	Exhibits	37

Signature		38

FORWARD-LOOKING STATEMENTS

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

•

capital expenditures,

•

earnings,

•

liquidity and capital resources,

•

litigation,

•

accounting matters,

•

possible corporate restructurings, acquisitions and dispositions,

•

compliance with debt and other restrictive covenants,

•

interest rates and dividends,

•

environmental matters,

•

nuclear operations, and

•

the overall economy of our service area.

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

•

electric utility deregulation or re-regulation,

•

regulated and competitive markets,

•

economic and capital market conditions,

•

changes in accounting requirements and other accounting matters,

•

changing weather,

•

the ultimate impact of the rulings by the Kansas Court of Appeals arising from appeals filed by interveners of portions of the Kansas Corporation Commission’s December 28, 2005 rate order,

•

the outcome of the Federal Energy Regulatory Commission transmission formula rate application filed on May 2, 2005,

•

the impact of regional transmission organizations and independent system operators, including the development of new market mechanisms for energy markets in which we participate,

•

rates, cost recoveries and other regulatory matters including the outcome of our request for reconsideration of the September 6, 2006 Federal Energy Regulatory Commission order,

•

the impact of changes and downturns in the energy industry and the market for trading wholesale electricity,

•

the outcome of the notice of violation received on January 22, 2004 from the Environmental Protection Agency and other environmental matters,

•

political, legislative, judicial and regulatory developments at the municipal, state and federal level,

•

the impact of our potential liability to David C. Wittig and Douglas T. Lake for unpaid compensation and benefits and the impact of claims they have made against us related to the termination of their employment and the publication of the report of the special committee of the board of directors,

•

the impact of changes in interest rates,

•

the impact of changes in interest rates on pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan assets,

•

the impact of changes in estimates regarding our Wolf Creek Generating Station decommissioning obligation,

•

changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of nuclear generating facilities,

•

uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal,

•

regulatory requirements for utility service reliability,

•

homeland security considerations,

•

coal, natural gas, oil and wholesale electricity prices,

•

availability and timely provision of our fuel supply, and

•

other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety and in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2005. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our operations and financial results may be included in our Annual Report on Form 10-K for the year ended December 31, 2005. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	September 30, 2006			December 31, 2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,071		$	38,539
Restricted cash		—			2,430
Accounts receivable, net		195,716			124,711
Inventories and supplies, net		136,570			101,818
Energy marketing contracts		45,851			55,948
Tax receivable		19,510			1,565
Deferred tax assets		19,732			19,211
Prepaid expenses		40,600			30,452
Regulatory assets		28,813			39,300
Other		19,479			61,646

Total Current Assets		515,342			475,620

PROPERTY, PLANT AND EQUIPMENT, NET		3,967,510			3,947,732

OTHER ASSETS:
Restricted cash		—			25,014
Regulatory assets		360,248			398,198
Nuclear decommissioning trust		103,663			100,803
Energy marketing contracts		17,377			75,698
Other		182,250			187,004

Total Other Assets		663,538			786,717

TOTAL ASSETS	$	5,146,390		$	5,210,069

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	—		$	100,000
Short-term debt		87,000			—
Accounts payable		127,929			109,807
Accrued taxes		124,194			100,568
Energy marketing contracts		29,559			11,710
Accrued interest		19,845			36,609
Regulatory liabilities		34,726			50,970
Other		99,125			140,403

Total Current Liabilities		522,378			550,067

LONG-TERM LIABILITIES:
Long-term debt, net		1,563,196			1,562,990
Deferred income taxes		885,211			911,135
Unamortized investment tax credits		60,465			65,558
Deferred gain from sale-leaseback		126,391			130,513
Accrued employee benefits		145,075			158,418
Asset retirement obligations		83,232			129,888
Energy marketing contracts		135			2,007
Regulatory liabilities		83,562			111,523
Other		144,424			150,531

Total Long-Term Liabilities		3,091,691			3,222,563

COMMITMENTS AND CONTINGENCIES (See Notes 7 and 8)

TEMPORARY EQUITY (See Note 2)		7,612			—

SHAREHOLDERS’ EQUITY:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares		21,436			21,436
Common stock, par value $5 per share; authorized 150,000,000 shares; issued 87,258,965 and 86,835,371 shares, respectively		436,295			434,177
Paid-in capital		912,832			923,083
Unearned compensation		—			(10,257	)
Retained earnings		195,154			109,987
Accumulated other comprehensive loss, net		(41,008	)		(40,987	)

Total Shareholders’ Equity		1,524,709			1,437,439

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,146,390		$	5,210,069

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended September 30,
	2006			2005
SALES	$	515,947		$	477,896

OPERATING EXPENSES:
Fuel and purchased power		169,053			132,030
Operating and maintenance		115,024			107,719
Depreciation and amortization		50,452			42,821
Selling, general and administrative		41,832			42,071

Total Operating Expenses		376,361			324,641

INCOME FROM OPERATIONS		139,586			153,255

OTHER INCOME (EXPENSE):
Investment earnings		1,140			4,732
Other income		4,285			848
Other expense		(4,271	)		(5,094	)

Total Other Income		1,154			486

Interest expense		25,757			26,886

INCOME BEFORE INCOME TAXES		114,983			126,855
Income tax expense		24,949			42,380

NET INCOME		90,034			84,475
Preferred dividends		242			242

EARNINGS AVAILABLE FOR COMMON STOCK	$	89,792		$	84,233

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):
Basic earnings available	$	1.03		$	0.97

Diluted earnings available	$	1.02		$	0.96

Average equivalent common shares outstanding		87,578,093			86,949,726
DIVIDENDS DECLARED PER COMMON SHARE	$	0.25		$	0.23

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)


	Nine Months Ended September 30,
	2006			2005
SALES	$	1,262,592		$	1,189,201

OPERATING EXPENSES:
Fuel and purchased power		390,803			343,437
Operating and maintenance		344,095			322,767
Depreciation and amortization		148,240			127,682
Selling, general and administrative		119,174			124,723

Total Operating Expenses		1,002,312			918,609

INCOME FROM OPERATIONS		260,280			270,592

OTHER INCOME (EXPENSE):
Investment earnings		5,973			9,252
Other income		16,753			7,931
Other expense		(10,333	)		(13,102	)

Total Other Income		12,393			4,081

Interest expense		74,203			84,488

INCOME BEFORE INCOME TAXES		198,470			190,185
Income tax expense		46,233			62,218

NET INCOME		152,237			127,967
Preferred dividends		727			727

EARNINGS AVAILABLE FOR COMMON STOCK	$	151,510		$	127,240

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (see Note 2):
Basic earnings available	$	1.73		$	1.47

Diluted earnings available	$	1.72		$	1.46

Average equivalent common shares outstanding		87,440,865			86,783,512
DIVIDENDS DECLARED PER COMMON SHARE	$	0.75		$	0.69

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)


	Three Months Ended September 30,
	2006			2005
NET INCOME	$	90,034		$	84,475

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized holding (loss) gain on marketable securities arising during the period		(53	)		40

Other Comprehensive (Loss) Income		(53	)		40

COMPREHENSIVE INCOME	$	89,981		$	84,515


	Nine Months Ended September 30,
	2006			2005
NET INCOME	$	152,237		$	127,967

OTHER COMPREHENSIVE INCOME (LOSS):
Unrealized holding (loss) gain on marketable securities arising during the period		(21	)		40

Other Comprehensive (Loss) Income		(21	)		40

COMPREHENSIVE INCOME	$	152,216		$	128,007

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2006			2005
				Revised (See Note 2)
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	152,237		$	127,967
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		148,240			127,682
Amortization of nuclear fuel		11,698			9,368
Amortization of deferred gain from sale-leaseback		(4,121	)		(7,095	)
Amortization of prepaid corporate-owned life insurance		12,204			12,928
Non-cash stock compensation		2,013			2,522
Net changes in energy marketing assets and liabilities		(10,186	)		(55,222	)
Accrued liability to certain former officers		1,710			2,418
Net deferred income taxes and credits		1,999			69,367
Stock based compensation excess tax benefits		(655	)		—
Changes in working capital items, net of acquisitions and dispositions:
Accounts receivable, net		(71,005	)		(25,725	)
Inventories and supplies		(34,752	)		27,444
Prepaid expenses and other		6,674			(40,537	)
Accounts payable		9,444			2,074
Accrued taxes		5,682			72,280
Other current liabilities		(40,697	)		(47,611	)
Changes in other, assets		(1,993	)		(15,949	)
Changes in other, liabilities		(31,848	)		(15,088	)

Cash flows from operating activities		156,644			246,823

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(200,367	)		(145,949	)
Purchase of securities within the nuclear decommissioning trust fund		(295,366	)		(271,325	)
Sale of securities within the nuclear decommissioning trust fund		291,961			267,613
Investment in corporate-owned life insurance		(19,127	)		(19,346	)
Proceeds from investment in corporate-owned life insurance		9,503			10,794
Proceeds from other investments		52,357			12,267

Cash flows used in investing activities		(161,039	)		(145,946	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		87,000			—
Proceeds from long-term debt		99,662			642,807
Retirements of long-term debt		(200,000	)		(741,847	)
Repayment of capital leases		(3,617	)		(3,686	)
Borrowings against cash surrender value of corporate-owned life insurance		58,370			56,532
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(10,017	)		(12,229	)
Stock based compensation excess tax benefits		655			—
Issuance of common stock, net		1,776			5,079
Cash dividends paid		(60,134	)		(55,859	)

Cash flows used in financing activities		(26,305	)		(109,203	)

NET CASH FLOWS FROM INVESTING ACTIVITIES OF DISCONTINUED OPERATIONS		1,232			—

NET DECREASE IN CASH AND CASH EQUIVALENTS		(29,468	)		(8,326	)

CASH AND CASH EQUIVALENTS:
Beginning of period		38,539			24,611

End of period	$	9,071		$	16,285

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

WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this quarterly report on Form 10-Q to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 667,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. KGE owns a 47% interest in the Wolf Creek Generating Station (Wolf Creek), a nuclear power plant located near Burlington, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2005 (2005 Form

10-K).

Use of Management’s Estimates

When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, 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, fuel costs billed under the terms of our retail energy cost adjustment (RECA), income taxes, pension and other post-retirement and post-employment benefits, our asset retirement obligations including decommissioning of Wolf Creek, environmental issues, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and nine months ended September 30, 2006 are not necessarily indicative of the results to be expected for the full year.

Dilutive Shares

Basic earnings 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 per share include the effects of potential issuances of common shares resulting from the assumed vesting of all outstanding RSUs and the exercise of all outstanding stock options issued pursuant to the terms of our stock-based compensation plans. The dilutive effect of shares issuable under our stock-based compensation plans is computed using the treasury stock method.

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
DENOMINATOR FOR BASIC AND DILUTED EARNINGS PER SHARE:
Denominator for basic earnings per share – weighted average equivalent shares	87,578,093	86,949,726	87,440,865	86,783,512
Effect of dilutive securities:
Employee stock options	1,069	1,901	931	1,784
Restricted share units	670,175	600,680	652,831	588,387

Denominator for diluted earnings per share – weighted average equivalent shares	88,249,337	87,552,307	88,094,627	87,373,683

Potentially dilutive shares not included in the denominator since they are antidilutive	162,570	214,340	162,570	214,340

Stock Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), “Share-Based Payment,” (SFAS No. 123R) for stock-based compensation plans. Under SFAS No. 123R, all stock-based compensation is measured at the grant date, based on the fair value of the award, and is recognized as an expense in the consolidated statements of income over the requisite service period. On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued Staff Accounting Bulletin (SAB) No. 107 on Share-Based Payment to express the views of the staff regarding the interaction between SFAS No. 123R and SEC rules and regulations as well as provide staff’s view on valuation of stock-based compensation arrangements for public companies. The SAB No. 107 guidance was taken into consideration with the implementation of SFAS No. 123R.

We adopted SFAS No. 123R using the modified prospective transition method. Under the modified prospective transition method, we are required to record stock-based compensation expense for all awards granted after the adoption date and for the unvested portion of previously granted awards outstanding as of the adoption date. Compensation cost related to the unvested portion of previously granted awards is based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123. Compensation cost for awards granted after the adoption date are based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. Since 2002, we have used RSUs exclusively for our stock-based compensation awards. RSUs are valued in the same manner under SFAS Nos. 123 and 123R.

The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(In Thousands)
Compensation expense	$	479	$	1,013	$	2,017	$	3,637
Income tax benefits related to stock-based compensation arrangements		190		403		802		1,447

The incremental amount of stock-based compensation expense that was disclosed and not included in our consolidated statements of income for the three and nine months ended September 30, 2005 was not material to our consolidated results of operations and did not change basic or diluted earnings per share.

Restricted share unit (RSU) awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined in SFAS No. 123R as nonvested shares and do not include restrictions once the awards have vested. We measure the fair value of the RSU awards based on the market price of the underlying common stock as of the date of grant and recognize that cost as an expense in the consolidated statements of income over the requisite service period. The requisite service periods range from one to ten years. RSU awards issued after adoption of SFAS No. 123R with only service conditions that have a graded vesting schedule will be recognized as an expense in the consolidated statements of income on a straight-line basis over the requisite service period for the entire award. Awards issued prior to adoption of SFAS No. 123R will continue to be recognized as an expense in the consolidated statements of income on a straight-line basis over the requisite service period for each separately vesting portion of the award.

During the nine months ended September 30, 2006, our RSU activity was as shown in the following table.


	Shares		Weighted Average Grant-Date Fair Value
	(In Thousands)
Restricted Share Units:
Nonvested balance as of January 1, 2006	1,094.5		$	18.54
Granted	83.1			21.55
Vested	(187.6	)		14.68
Forfeited	(12.7	)		21.57

Nonvested balance as of September 30, 2006	977.3			19.71

Total unrecognized compensation cost related to RSU awards was $3.7 million as of September 30, 2006. We expect to recognize these costs over a remaining weighted-average period of 5.5 years. Upon adoption of SFAS No. 123R, we were required to charge $10.3 million of unearned stock compensation against additional paid-in capital. There were no modifications of awards during the three and nine months ended September 30, 2006 or 2005.

SFAS No. 123R requires that forfeitures be estimated over the vesting period, rather than being recognized as a reduction of compensation expense when the forfeiture actually occurs. The cumulative effect of the use of the estimated forfeiture method for prior periods upon adoption of SFAS No. 123R was not material.

RSU awards that can be settled in cash upon a change in control were reclassified from permanent equity to temporary equity upon adoption of SFAS No. 123R. As of September 30, 2006, we had $7.6 million of temporary equity on our consolidated balance sheet. If we determine it is probable that these awards will be settled in cash, the awards will be reclassified as a liability.

Stock options granted between 1996 and 2001 are completely vested and expire 10 years from the date of grant. All 165,670 outstanding options are exercisable. There were 150 options exercised and 39,070 options forfeited during the three months ended September 30, 2006. During the nine months ended September 30, 2006, there were 3,975 options exercised and 49,945 options forfeited. We currently have no plans to issue new stock option awards.

Prior to the adoption of SFAS No. 123R, we reported all tax benefits resulting from the vesting of RSU awards and exercise of stock options as operating cash flows in the consolidated statements of cash flows. SFAS No. 123R requires cash retained as a result of excess tax benefits resulting from the tax deductions in excess of the related compensation cost recognized in the financial statements to be classified as cash flows from financing activities in the consolidated statements of cash flows.

Supplemental Cash Flow Information


	Nine Months Ended September 30,
	2006		2005
	(In Thousands)
CASH PAID FOR:
Interest on financing activities, net of amount capitalized	$	81,835	$	82,248
Income taxes		61,632		212
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		19,218		6,867
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and RSUs		7,377		10,054
Assets acquired through capital leases		3,728		3,204

New Accounting Pronouncements

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the Financial Accounting Standards Board (FASB) released SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132(R).” Under the new standard, companies must recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on their balance sheets. The recognition and disclosure provisions of SFAS No. 158 are required to be adopted as of December 31, 2006. We are still evaluating the final impact this standard will have on our consolidated financial statements, but believe at this time that it will decrease equity by approximately $90.0 million, net of tax. We are pursuing regulatory authority to allow us to recognize this item as a regulatory asset pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” rather than as a charge to equity. The actual impact of the adoption of SFAS No. 158 could differ significantly from this estimate due to plan asset performance for the year, the discount rates in effect when plan liabilities are measured and regulatory treatment.

SFAS No. 157 – Fair Value Measurements

In September 2006, FASB released SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We anticipate adopting the guidance effective January 1, 2008. We are currently evaluating what impact the adoption of SFAS No. 157 will have on our consolidated financial statements.

SAB No. 108 – Effects of Prior Year Misstatements on Current Year Financial Statements

In September 2006, the staff of the SEC released SAB No. 108 on Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of either (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). The guidance provided in SAB No. 108 requires both methods to be used in quantifying a misstatement. This guidance should be applied to annual financial statements for fiscal years ending after November 15, 2006. The cumulative effect of the change in method of quantifying errors, if any, can be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year with the offsetting adjustment made to the opening balance of retained earnings for that year. Alternatively, a company may restate prior periods. SAB No. 108 requires disclosure of the nature and amount of each individual error being corrected in the cumulative adjustment, as well as disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. We are currently evaluating the effect this bulletin will have on our consolidated financial statements, but believe it will not have an impact.

FIN 48 – Accounting for Uncertainty in Income Taxes

In July 2006, FASB released FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” FIN 48 prescribes a comprehensive model for how companies should recognize, measure and disclose in their financial statements uncertain tax positions taken, or expected to be taken, on a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006 with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We anticipate adopting the guidance effective January 1, 2007. We are currently evaluating what impact the adoption of FIN 48 will have on our consolidated financial statements.

Reclassifications and Revisions

We have reclassified and revised certain prior year amounts to conform with classifications used in the current-year presentation as necessary for a fair presentation of the financial statements. We have revised the prior year’s presentation of our consolidated statements of cash flows to reflect investments in and proceeds from purchases and sales of marketable securities in our nuclear decommissioning trust on a gross basis, rather than net.

3. RATE MATTERS AND REGULATION

Potential Changes in Rates

In accordance with a 2003 Kansas Corporation Commission (KCC) order, on May 2, 2005, we filed applications with the KCC for it to review our retail electric rates. On December 28, 2005, the KCC issued an order (2005 KCC Order) authorizing changes in our rates, which we began billing in the first quarter of 2006, and approving various other changes to our rate structures. The new rates are discussed in greater detail in our 2005 Form 10-K. In April 2006, interveners to the rate review filed appeals with the Kansas Court of Appeals challenging various aspects of the 2005 KCC Order. On July 7, 2006, the Kansas Court of Appeals reversed and remanded for further consideration by the KCC three elements of the 2005 KCC Order. The balance of the 2005 KCC Order was upheld.

The Kansas Court of Appeals held: (1) the KCC’s approval of a transmission delivery charge, in the circumstances of this case, violated the Kansas statutes that authorize a transmission delivery charge, (2) the KCC’s approval of recovery of terminal net salvage, adjusted for inflation, in our depreciation rates was not supported by substantial competent evidence, and (3) the KCC’s reversal of its prior rate treatment of the La Cygne Generating Station (La Cygne) Unit 2 sale-leaseback transaction was not sufficiently justified and was thus unreasonable, arbitrary and capricious.

At this time, we are unable to predict the ultimate impact of the decision by the Kansas Court of Appeals or when we will be able to determine such impact. We believe the decision on these three issues was erroneous and we and one other party have filed petitions for review of the decision with the Kansas Supreme Court setting forth the reasons we believe the decision should be reversed. The Kansas Supreme Court has discretion to grant or deny the petitions for review and has not yet ruled on the petitions. If the Kansas Supreme Court does not grant the petitions for review, or affirms the decision of the Kansas Court of Appeals, on remand the KCC will consider further the portions of its order that were reversed. We are unable to predict the actions the KCC may take on the relevant issues. On remand, the KCC could require that we refund amounts collected to date to the extent that such amounts exceed the amounts authorized in a new order issued by the KCC. We have not recorded any potential refund obligations related to these issues.

We are currently recovering approximately $14.0 million annually related to terminal net salvage. Through September 30, 2006, we have recovered $9.4 million. If we cannot continue recovering terminal net salvage, the impact would be a decrease in cash flow. Amounts we are currently recovering in rates for terminal net salvage are recorded as a regulatory liability. If the rate treatment of the La Cygne Unit 2 sale-leaseback transaction is reversed, the impact would be an annual decrease of approximately $8.0 million in our income from operations.

FERC Proceedings

Request for Change in Transmission Rates

On May 2, 2005, we filed applications with the Federal Energy Regulatory Commission (FERC) that proposed a formula transmission rate providing for annual adjustments to reflect changes in our transmission costs. This is consistent with our proposals filed with the KCC on May 2, 2005 to charge retail customers separately for transmission service through a transmission delivery charge. These proposed FERC transmission rates became effective, subject to refund, December 1, 2005. We reached a settlement with all parties in the FERC transmission rate proceeding. The parties submitted the settlement to the FERC settlement judge on July 7, 2006 and the judge subsequently certified the settlement for approval. We anticipate a decision from FERC during the fourth quarter of 2006. We can provide no assurance that FERC will ultimately approve the settlement. As of September 30, 2006 we had recorded a refund obligation of $2.3 million, which we believe to be consistent with the provisions of the July 7, 2006 settlement agreement.

Market-based Rates

On March 23, 2005, FERC instituted a proceeding concerning the reasonableness of our market-based rates in our electric control area and the electrical control areas of Midwest Energy, Inc. and Aquila, Inc.’s West Plains – Kansas Energy division. We provided FERC with information it requested for its analysis. On September 6, 2006, FERC issued an order (2006 FERC Order) conditionally accepting a settlement that confirms the cost-based prices we can charge for future wholesale power sales made inside the referenced control areas. In addition, FERC confirmed that we can charge market-based prices for future wholesale power sales made outside the referenced control areas. We do not expect this portion of the 2006 FERC Order to significantly impact our future consolidated results of operations.

The 2006 FERC Order also requires that we make refunds, with interest, to the extent that we made wholesale power sales after June 7, 2005 at prices above the prices permitted under the mitigation proposal accepted by FERC. This refund obligation applies to certain wholesale power sales made inside the referenced control areas for consumption outside the referenced control areas at market-based prices that exceeded the cost-based prices permitted by the 2006 FERC Order.

We believe our potential refund liability is limited principally to wholesale power sales made at market-based prices after June 7, 2005 inside the referenced control areas for consumption outside the referenced control areas. We believe the potential refund liability does not apply, for example, to any wholesale power sales made outside the referenced control areas for delivery and consumption outside the referenced control areas or to sales made to other utilities under long-term cost-based contracts or cost-of-service tariffs. Substantially all of our market-based wholesale sales made after April 2006 were sold outside the referenced control areas for delivery and consumption outside the referenced control areas. Furthermore, we believe that any refund liability will reduce the credit we are required to make under our retail energy cost adjustment to recoverable fuel costs based on the average of the margins realized from market-based wholesale sales. We have recorded a refund obligation of $0.7 million as of September 30, 2006, which we believe is consistent with the provisions of the 2006 FERC Order.

We requested a rehearing of the 2006 FERC Order and are considering other administrative or legal remedies that may be available to us.

4. ACCOUNTS RECEIVABLE SALES PROGRAM

We terminated our accounts receivable sales program in March 2006. As of December 31, 2005, $65.0 million was sold to the bank and commercial paper conduit.

5. DEBT FINANCINGS

On June 1, 2006, we refinanced $100.0 million of pollution control bonds, which were to mature in 2031. We replaced this issue with two new pollution control bond series of $50.0 million each. One series carries an interest rate of 4.85% and matures in 2031. The second series carries a variable interest rate and also matures in 2031.

On March 17, 2006, Westar Energy amended and restated its revolving credit facility dated May 6, 2005 to increase the size of the facility, extend its term and reduce borrowing costs. The amended and restated revolving credit facility matures on March 17, 2011. So long as there is no default or event of default under the revolving credit facility, we may elect to extend the term of the credit facility for up to an additional two years, subject to lender participation. The facility allows us to borrow up to an aggregate amount of $500.0 million, including letters of credit up to a maximum aggregate amount of $150.0 million. We may elect, subject to FERC approval, to increase the aggregate amount of borrowings under the facility to $750.0 million by increasing the commitment of one or more lenders who have agreed to such increase, or by adding one or more new lenders with the consent of the Administrative Agent and any letter of credit issuing bank, which will not be unreasonably withheld, so long as there is no default or event of default under the revolving credit facility.

On January 17, 2006, we repaid $100.0 million aggregate principal amount of 6.2% first mortgage bonds with cash on hand and borrowings under the revolving credit facility.

6. INCOME TAXES AND TAXES OTHER THAN INCOME TAXES

We recorded income tax expense of approximately $24.9 million with an effective income tax rate of 22% for the three months ended September 30, 2006, and $42.4 million with an effective income tax rate of 33% for the same period of 2005. The decrease in the effective tax rate is due primarily to increases in non-taxable income from corporate-owned life insurance and the deduction for qualified domestic production activities, and the reversal of tax reserves as a result of a favorable re-evaluation of uncertain tax positions.

We recorded income tax expense of $46.2 million with an effective tax rate of 23% for the nine months ended September 30, 2006, and $62.2 million with an effective tax rate of 33% for the same period of 2005. The decrease in the effective tax rate is due primarily to the utilization of previously unrecognized capital loss carryforwards to offset realized capital gains, increases in non-taxable income from corporate-owned life insurance and the deduction for qualified domestic production activities, and the reversal of tax reserves as a result of a favorable re-evaluation of uncertain tax positions.

As of September 30, 2006 and December 31, 2005, we had recorded a reserve for uncertain tax positions of $51.0 million and $50.8 million, respectively. The tax positions may involve income, deductions or credits reported in prior year income tax returns that we believe were treated properly on such tax returns. The tax returns containing these tax reporting positions are currently under audit or will likely be audited by the Internal Revenue Service or other taxing authorities. The timing of the resolution of these audits is uncertain. If the positions taken on the tax returns are ultimately upheld or not challenged within the time available for such challenges, we will reverse these tax provisions to income. If the positions taken on the tax returns are determined to be inappropriate, we may be required to make cash payments for taxes and interest. The reserves are determined based on our best estimate of probable assessments by the applicable taxing authorities and are adjusted, from time to time, based on changing facts and circumstances. During the three months ended September 30, 2006, we reassessed the liability related to uncertain income tax positions and reduced our tax reserve by $2.3 million. The decrease in the reserve was offset by additional interest accruals.

As of September 30, 2006 and December 31, 2005, we also had a reserve of $6.7 million and $6.1 million, respectively, for probable assessments of taxes other than income taxes.

7. COMMITMENTS AND CONTINGENCIES

Environmental Projects

Kansas City Power & Light Company began updating or installing additional equipment related to emissions controls at La Cygne Unit 1 in 2005. We will continue to incur costs through the scheduled completion in 2009. We anticipate that our share of these capital costs may be approximately $105.0 million. Additionally, we have identified the potential for up to $515.0 million of capital expenditures at other power plants for environmental projects during approximately the next eight years. This amount could increase depending on the resolution of the Environmental Protection Agency (EPA) New Source Review described below. In addition to the capital investment, were we to install such equipment, we anticipate that we would incur significant annual expense to operate and maintain the equipment and the operation of the equipment would reduce net production from our plants. The environmental cost recovery rider (ECRR) approved in the 2005 KCC Order allows for the timely inclusion in rates of capital expenditures tied directly to environmental improvements required by the Clean Air Act. However, increased operating and maintenance costs, other than expenses related to production-related consumables, such as limestone, can be recovered only through a change in base rates following a rate review.

The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Both the timing and the nature of required investments depend on specific outcomes that result from interpretation of regulations, new regulations, legislation, and the resolution of the EPA New Source Review described below. In addition, the availability of equipment and contractors can affect the timing and ultimate cost of equipment installation. Whether through base rates or the ECRR, we expect to recover such costs through the rates we charge our customers.

EPA New Source Review

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

The EPA requested information from us under Section 114 regarding projects and maintenance activities that have been conducted since 1980 at three coal-fired plants we operate. On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated 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. 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 the ECRR. 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. We are not able to estimate the possible loss or range of loss at this time.

8. LEGAL PROCEEDINGS

We and certain of our present and former officers and directors were 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. In early April 2005, we reached an agreement in principle with the plaintiffs to settle this lawsuit for $30.0 million. The full terms of the proposed settlement are set forth in a Stipulation and Agreement of Compromise, Settlement and Release dated as of May 31, 2005 filed with the court. On September 1, 2005, the court approved the proposed settlement and directed the parties to consummate the settlement in accordance with the stipulation. Pursuant to the stipulation, we paid $1.25 million and our insurance carriers paid $28.75 million into a settlement fund that upon effectiveness of the settlement will be disbursed, after payment of $9.0 million of legal fees for plaintiffs’ counsel plus expenses, to shareholders as provided in the stipulation. The amounts paid by our insurance carriers in this settlement include the payments related to the settlement of the shareholder derivative lawsuit described below. This settlement became effective on June 21, 2006.

Certain present and former members of our board of directors and officers were 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.” In early April 2005, a special litigation committee of our board of directors approved an agreement in principle to settle this lawsuit for $12.5 million to be paid to us by our insurance carriers. The full terms of the proposed settlement are set forth in a Stipulation and Agreement of Compromise, Settlement and Release dated May 31, 2005 filed with the court. On September 1, 2005, the court approved the proposed settlement and directed the parties to consummate the settlement in accordance with the stipulation. Pursuant to the stipulation, the recovery from our insurance carriers, less attorney’s fees of $2.5 million, was paid into the settlement fund for the settlement of the securities class action lawsuit as described above. On September 16, 2005, one shareholder filed a motion asking the court to reconsider its order approving the settlement. The court denied this motion on December 2, 2005, and the shareholder then filed a timely appeal with the United States Court of Appeals for the Tenth Circuit. This appeal was dismissed on June 21, 2006 and the settlement is now effective.

We and certain of our present and former officers and employees were 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.” The lawsuit was brought on behalf of participants in, and beneficiaries of, our Employees’ 401(k) Savings Plan between July 1, 1998 and January 1, 2003. On January 31, 2006, we reached an agreement in principle with the plaintiffs to settle this lawsuit for $9.25 million to be paid by our insurance carrier. The full terms of the proposed settlement are set forth in a Class Action Settlement Agreement dated March 23, 2006 filed with the court. On July 27, 2006, the court issued an order that approved the proposed settlement, approved plaintiffs’ attorneys’ fees and litigation expenses totaling $2.9 million to be paid from the settlement fund, and directed the parties to consummate the settlement in accordance with the settlement agreement.

In connection with the settlement of these lawsuits, we disbursed funds during the three months ended September 30, 2006. Funds related to the amounts to be paid to the plaintiffs when the settlements became final had previously been recorded in other current liabilities.

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 final resolution of the criminal charges filed by the United States Attorney’s Office against Mr. Wittig and Mr. Lake in U.S. District Court in the District of Kansas. On September 12, 2005, the jury convicted Mr. Wittig and Mr. Lake on the charges relevant to each of them. Mr. Wittig and Mr. Lake have appealed these convictions. We are unable to predict the ultimate impact of this matter on our consolidated results of operations.

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 results of operations.

See also Notes 3, 7, 9 and 10 for discussion of a decision made by the Kansas Court of Appeals regarding our rates, alleged violations of the Clean Air Act, an investigation by the United States Department of Labor and potential liabilities to Mr. Wittig and Mr. Lake.

9. ONGOING INVESTIGATIONS – 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 pension benefit plan. We have provided information to the Department of Labor pursuant to the subpoena and subsequent inquiries. 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 8, “Legal Proceedings,” for discussion of a class action lawsuit brought on behalf of participants in our Employees’ 401(k) Savings Plan.

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

During the nine months ended September 30, 2006, we increased the amount of our accrued liability for potential obligations to Mr. Wittig and Mr. Lake by $12.9 million to $73.0 million from $60.1 million as of December 31, 2005. The increase in the amount of the liability was for changes in potential benefits due under an executive salary continuation plan, changes in split-dollar life insurance benefits, dividends and dividend equivalents related to RSUs and deferred vested stock for compensation, and potential obligations related to the cash received for Guardian International, Inc. (Guardian) preferred stock as discussed in Note 11, “Guardian International Preferred Stock.” As discussed above in Note 8, “Legal Proceedings,” we have filed a demand for arbitration with the American Arbitration Association seeking to avoid paying compensation and other benefits Mr. Wittig and Mr. Lake claim to be owed to them.

In addition, as of September 30, 2006 we had accrued $8.4 million for legal fees and expenses incurred by Mr. Wittig and Mr. Lake that are recorded in accounts payable on our consolidated balance sheets. These legal fees and expenses were incurred in the defense of the criminal charges filed by the United States Attorney’s Office in Topeka, Kansas. On September 12, 2005, the jury convicted Mr. Wittig and Mr. Lake on the charges relevant to each of them. We will likely incur substantial additional expenses for legal fees and expenses incurred by Mr. Wittig and Mr. Lake related to their appeal of these convictions and the arbitration proceeding discussed above. We have filed lawsuits against Mr. Wittig and Mr. Lake claiming that the legal fees and expenses they have incurred, which we have advanced or for which they seek advancement in the defense of the criminal charges, are unreasonable and excessive. We have asked the court to determine the amount of the legal fees and expenses that were reasonably incurred and for which we have an obligation to advance. We are unable to estimate the amount of the legal fees and expenses incurred or 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.

The jury in the trial of Mr. Wittig and Mr. Lake also determined that Mr. Wittig and Mr. Lake should forfeit to the United States certain property that it determined was derived from their criminal conduct. We subsequently filed petitions asserting a superior interest in certain forfeited property. The court subsequently entered final orders of forfeiture awarding us certain property forfeited by Mr. Wittig and Mr. Lake. The property awarded to us consists substantially of compensation and benefits that we were seeking to avoid paying in the arbitration proceeding referenced above. Mr. Wittig and Mr. Lake have appealed their convictions and the forfeiture orders.

11. GUARDIAN INTERNATIONAL PREFERRED STOCK

On March 6, 2006, Guardian was acquired by Devcon International Corporation in a merger. In connection with this merger, we received approximately $23.2 million for 15,214 shares of Guardian Series D preferred stock and 8,000 shares of Guardian Series E preferred stock held of record by us. We beneficially owned 354.4 shares of the Guardian Series D preferred stock and 312.9 shares of the Guardian Series E preferred stock. During the nine months ended September 30, 2006, we recorded a gain of approximately $0.3 million as a result of the payment for these shares. Certain current and former officers beneficially owned the remaining shares. Of these shares, 14,094 shares of Guardian Series D preferred stock and 7,276 shares of Guardian Series E preferred stock were beneficially owned by Mr. Wittig and Mr. Lake. The ownership of the shares beneficially owned by Mr. Wittig and Mr. Lake, as well as related dividends, and now the cash received for the shares, is disputed and is the subject of the arbitration proceeding with Mr. Wittig and Mr. Lake discussed in Note 8, “Legal Proceedings.” These shares were, and now the cash received for the shares are, also part of the property forfeited by Mr. Wittig and Mr. Lake in the criminal proceeding discussed in Note 10, “Potential Liabilities to David C. Wittig and Douglas T. Lake.” As a result of this transaction, we no longer hold any Guardian securities.

12. ASSET RETIREMENT OBLIGATIONS

Wolf Creek Nuclear Operating Corporation (WCNOC), the operating company for Wolf Creek, filed a request for a 20 year extension of Wolf Creek’s operating license with the Nuclear Regulatory Commission (NRC) in September 2006. Currently, the operating license will expire in 2025. We anticipate that the NRC may take up to two years before it rules on the request. The NRC may impose conditions as part of any approval. Based on the experience of other nuclear plant operators, we believe that the NRC will ultimately approve the request. Therefore, we have adjusted our asset retirement obligation (ARO) to reflect the revision in our estimate of the timing of the cash flows that we will incur to satisfy this obligation.

The change in the balance of the ARO liability from December 31, 2005 through September 30, 2006 is summarized in the following table.


Balance as of December 31, 2005	$	129,888
Liabilities incurred		218
Liabilities settled		(438	)
Accretion expense		7,068
Revision to nuclear decommissioning ARO liability		(53,504	)

Balance as of September 30, 2006	$	83,232

13. DISCONTINUED OPERATIONS

During the nine months ended September 30, 2006, we received proceeds of $1.2 million that were released from an escrow account arising from the sale of Protection One Europe, a security business we sold on June 30, 2003. The sale is discussed in greater detail in Note 23, “Discontinued Operations – Sale of Protection One and Protection One Europe,” in our 2005 Form 10-K.

14. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2006			2005			2006			2005
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,737		$	1,566		$	153		$	99
Interest cost		7,819			6,355			1,600			1,623
Expected return on plan assets		(8,970	)		(7,858	)		(731	)		(645	)
Amortization of Unrealized:
Transition obligation, net		—			—			982			1,014
Prior service costs (benefits)		701			602			(176	)		(119	)
Actuarial loss, net		2,123			1,169			307			406

Net periodic cost	$	4,410		$	1,834		$	2,135		$	2,378


	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2006			2005			2006			2005
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	6,883		$	4,826		$	1,119		$	1,225
Interest cost		22,891			20,703			5,156			5,345
Expected return on plan assets		(26,954	)		(25,970	)		(2,229	)		(1,935	)
Amortization of Unrealized:
Transition obligation, net		—			—			2,948			2,980
Prior service costs (benefits)		2,169			1,984			(310	)		(353	)
Actuarial loss, net		6,571			3,903			1,501			1,466

Net periodic cost	$	11,560		$	5,446		$	8,185		$	8,728

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

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended September 30,	2006			2005			2006		2005
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	812		$	705		$	62	$	60
Interest cost		1,073			932			102		96
Expected return on plan assets		(857	)		(779	)		—		—
Amortization of Unrealized:
Transition obligation, net		14			14			15		15
Prior service costs		8			8			—		—
Actuarial loss, net		453			336			49		42

Net periodic cost	$	1,503		$	1,216		$	228	$	213


	Pension Benefits						Post-retirement Benefits
Nine Months Ended September 30,	2006			2005			2006		2005
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,430		$	2,121		$	186	$	179
Interest cost		3,212			2,806			308		288
Expected return on plan assets		(2,565	)		(2,344	)		—		—
Amortization of Unrealized:
Transition obligation, net		42			42			45		45
Prior service costs		24			24			—		—
Actuarial loss, net		1,357			1,010			147		126

Net periodic cost	$	4,500		$	3,659		$	686	$	638

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

INTRODUCTION

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

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2006, and our operating results for the three and nine months ended September 30, 2006 and 2005. As you read Management’s Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Potential Changes in Rates

In accordance with a 2003 KCC order, on May 2, 2005, we filed applications with the KCC for it to review our retail electric rates. The 2005 KCC Order authorized changes in our rates, which we began billing in the first quarter of 2006, and approved various other changes to our rate structures. The new rates are discussed in greater detail in our 2005 Form 10-K. In April 2006, interveners to the rate review filed appeals with the Kansas Court of Appeals challenging various aspects of the 2005 KCC Order. On July 7, 2006, the Kansas Court of Appeals reversed and remanded for further consideration by the KCC three elements of the 2005 KCC Order. The balance of the 2005 KCC Order was upheld. We and one other party have filed petitions for review of the decision with the Kansas Supreme Court. For additional information, see Note 3 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation.”

Forfeiture of Assets by David C. Wittig and Douglas T. Lake

The jury in the trial of Mr. Wittig and Mr. Lake determined that Mr. Wittig and Mr. Lake should forfeit to the United States certain property that it determined was derived from their criminal conduct. We subsequently filed petitions asserting a superior interest in certain forfeited property. The court subsequently entered final orders of forfeiture awarding us certain property forfeited by Mr. Wittig and Mr. Lake. The property awarded to us consists substantially of compensation and benefits that we were seeking to avoid paying in the arbitration proceeding as discussed in Note 8 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.” Mr. Wittig and Mr. Lake have appealed their convictions and the forfeiture orders.

Corporate-Owned Life Insurance

Our earnings for the three and nine months ended September 30, 2006 reflect income of $3.9 million and $15.5 million, respectively, from proceeds of corporate-owned life insurance. This is included in other income in the consolidated statements of income for the three and nine months ended September 30, 2006.

Coal Inventory and Delivery

Coal deliveries from the Powder River Basin region of Wyoming to our coal-fired generating stations have improved recently; however, they continue to be below both historical experience and the rate at which we desire to receive deliveries. During 2005 and the first nine months of 2006, we implemented compensating measures based on delivery cycle times, our assumptions about future delivery cycle times, fuel usage and planned inventory levels. These measures have resulted in an increase in our inventory levels. We may continue to use those or other measures as conditions require. The compensating measures include, but are not limited to: reducing coal consumption during certain periods, revising normal operational dispatch of our generating units, purchasing power from others, reducing wholesale sales and leasing or acquiring additional rail cars. During the nine months ended September 30, 2006, the effects of additional purchased power expense and the reduction in sales due to slower coal deliveries have been partially offset by higher market-based wholesale sales prices. During the last quarter of 2006, we began operating our plants unrestricted by coal conservation.

Market-based Rates

On March 23, 2005, FERC instituted a proceeding concerning the reasonableness of our market-based rates in our electric control area and the electrical control areas of Midwest Energy, Inc. and Aquila, Inc.’s West Plains – Kansas Energy division. We provided FERC with information it requested for its analysis. On September 6, 2006, FERC issued an order conditionally accepting a settlement that confirms the cost-based prices we can charge for future wholesale power sales made inside the referenced control areas. The 2006 FERC Order also requires that we make refunds, with interest, to the extent that we made wholesale power sales after June 7, 2005 at prices above the prices permitted under the mitigation proposal accepted by FERC. We requested a rehearing of the 2006 FERC Order and are considering other administrative or legal remedies that may be available to us. For additional information see Note 3 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation – FERC Proceedings – Market-based Rates.”

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with GAAP. Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted in our 2005 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

As of September 30, 2006, ARO estimates were revised as discussed below. We have not experienced any other significant changes in our critical accounting estimates. For additional information, see our 2005 Form 10-K.

Asset Retirement Obligations

In September 2006, we revised our estimate of the timing of cash flows related to the decommissioning of Wolf Creek and adjusted our related ARO liability as discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations.”

OPERATING RESULTS

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

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

Other retail: Sales of energy for lighting public streets and highways, net of revenue subject to refund.

Tariff-based wholesale: Sales of energy to electric cooperatives, municipalities and other electric utilities, the rates for which are generally based on traditional cost-of-service pricing as prescribed by FERC tariffs. This category also includes changes in valuations of contracts that have yet to settle.

Market-based wholesale: Sales of energy to wholesale customers, the rates for which are generally based on prevailing market prices as allowed by our FERC approved market-based tariff, or where not permitted, pricing is based on incremental cost plus a permitted margin. This category also includes changes in valuations of contracts that have yet to settle.

Energy marketing: Includes: (1) market-based transactions unrelated to our price-regulated electricity sales; (2) financially settled products and physical transactions sourced outside our control area; and (3) changes in valuations for contracts that have yet to settle that may not be recorded in tariff- or market-based wholesale revenues.

Transmission: Reflects transmission revenues, including those based on a tariff with the Southwest Power Pool (SPP).

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others.

Regulated electric utility sales are significantly impacted by such things as rate regulation, customer conservation efforts, wholesale demand, the economy of our service area, the weather and competitive forces. Our wholesale sales are impacted by, among other factors, demand, cost of fuel and purchased power, price volatility, available generation capacity and transmission availability. Changing weather affects the amount of electricity our customers use. Very hot summers and very cold winters prompt more demand, especially among our residential customers. Mild weather reduces demand.

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

Below we discuss our operating results for the three months ended September 30, 2006 compared to the results for the three months ended September 30, 2005. Changes in results of operations are as follows.


	Three Months Ended September 30,
	2006			2005			Change			% Change
	(In Thousands, Except Per Share Amounts)
SALES:
Residential	$	178,065		$	165,062		$	13,003		7.9
Commercial		136,930			124,607			12,323		9.9
Industrial		73,930			63,760			10,170		16.0
Other retail		(52	)		256			(308	)	(120.3	)

Total Retail Sales		388,873			353,685			35,188		9.9
Tariff-based wholesale		60,935			61,694			(759	)	(1.2	)
Market-based wholesale		24,543			30,406			(5,863	)	(19.3	)
Energy marketing		12,559			6,897			5,662		82.1
Transmission (a)		22,609			19,002			3,607		19.0
Other		6,428			6,212			216		3.5

Total Sales		515,947			477,896			38,051		8.0

OPERATING EXPENSES:
Fuel and purchased power		169,053			132,030			37,023		28.0
Operating and maintenance		115,024			107,719			7,305		6.8
Depreciation and amortization		50,452			42,821			7,631		17.8
Selling, general and administrative		41,832			42,071			(239	)	(0.6	)

Total Operating Expenses		376,361			324,641			51,720		15.9

INCOME FROM OPERATIONS		139,586			153,255			(13,669	)	(8.9	)

OTHER INCOME (EXPENSE):
Investment earnings		1,140			4,732			(3,592	)	(75.9	)
Other income		4,285			848			3,437		405.3
Other expense		(4,271	)		(5,094	)		823		16.2

Total Other Income		1,154			486			668		137.4

Interest expense		25,757			26,886			(1,129	)	(4.2	)

INCOME BEFORE INCOME TAXES		114,983			126,855			(11,872	)	(9.4	)
Income tax expense		24,949			42,380			(17,431	)	(41.1	)

NET INCOME		90,034			84,475			5,559		6.6
Preferred dividends		242			242			—		—

EARNINGS AVAILABLE FOR COMMON STOCK	$	89,792		$	84,233		$	5,559		6.6

BASIC EARNINGS PER SHARE	$	1.03		$	0.97		$	0.06		6.2

(a)

Transmission: Includes the SPP network transmission tariff. For the three months ended September 30, 2006, our SPP network transmission costs were approximately $20.2 million. This amount, less approximately $1.5 million that was retained by the SPP as administration cost, was returned to us as revenue. For the three months ended September 30, 2005, our SPP network transmission costs were approximately $16.3 million with an administration cost of approximately $1.6 million retained by the SPP.

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


	Three Months Ended September 30,
	2006	2005	Change		% Change
	(Thousands of MWh)
Residential	2,201	2,198	3		0.1
Commercial	2,089	2,110	(21	)	(1.0	)
Industrial	1,533	1,451	82		5.7
Other retail	22	25	(3	)	(12.0	)

Total Retail	5,845	5,784	61		1.1
Tariff-based wholesale	1,541	1,620	(79	)	(4.9	)
Market-based wholesale	492	547	(55	)	(10.1	)

Total	7,878	7,951	(73	)	(0.9	)

The increase in retail sales reflects the change in rates, including the effect of implementing the RECA authorized by the 2005 KCC Order. Market-based wholesale sales declined due to a decrease in volumes sold and a 10% decrease in the average price per MWh. The increase in energy marketing reflects generally favorable contract valuations due primarily to favorable changes in market prices since we entered into the contracts.

Operating and maintenance expense increased due primarily to a $3.9 million increase in SPP network transmission costs, the amortization of $2.9 million of previously deferred storm expense as authorized by the 2005 KCC Order and a $2.5 million increase in taxes other than income taxes, due primarily to higher property taxes. Operating and maintenance expense in 2005 included a $3.5 million charge related to terminating development of a plant operating system at Wolf Creek.

Depreciation expense increased due primarily to the change in our depreciation rates. Our rates as authorized by the KCC provide for recovery of this increase.

Investment earnings decreased due primarily to a decrease in interest income and the cessation of the accrual of carrying costs for regulatory assets that we have now begun amortizing pursuant to the 2005 KCC Order. During the three months ended September 30, 2005, we recorded $1.8 million of interest income on our share of the proceeds related to the settlement of litigation involving Wolf Creek and accrued $0.9 million of carrying costs on the regulatory assets related to the January 2002 and 2005 ice storms. In February 2006, we began amortizing the regulatory assets related to the two ice storms pursuant to the 2005 KCC Order and no longer accrue carrying costs.

Other income increased due to corporate-owned life insurance proceeds. Income received from corporate-owned life insurance was $3.9 million during the three months ended September 30, 2006 and $0.2 million during the same period of 2005.

Interest expense on long-term debt decreased due primarily to a lower long-term debt balance. Partially offsetting this decline was an increase in interest expense on short-term debt due to increased borrowings under our revolving credit facility.

Income taxes for the interim periods presented are based on our estimate of the annual effective income tax rate and are adjusted for the effect of significant infrequent or unusual items. Our estimate of the annual effective income tax rate may differ from the statutory Federal income tax rate of 35% due to permanent differences between income for financial reporting purposes and income for tax reporting purposes, recognition or reversal of valuation allowances related to capital losses and net operating loss carry forwards and tax credits. The effective income tax rate was 22% for the three months ended September 30, 2006 and 33% for the same period of 2005. The decrease in the effective tax rate is due primarily to increases in non-taxable income from corporate-owned life insurance and the deduction for qualified domestic production activities, and the reversal of tax reserves as a result of a favorable re-evaluation of uncertain tax positions.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Below we discuss our operating results for the nine months ended September 30, 2006 compared to the results for the nine months ended September 30, 2005. Changes in results of operations are as follows.


	Nine Months Ended September 30,
	2006			2005			Change			% Change
	(In Thousands, Except Per Share Amounts)
SALES:
Residential	$	390,360		$	361,949		$	28,411		7.8
Commercial		342,966			309,432			33,534		10.8
Industrial		205,072			180,848			24,224		13.4
Other retail		(3,976	)		666			(4,642	)	(697.0	)

Total Retail Sales		934,422			852,895			81,527		9.6
Tariff-based wholesale		150,284			143,552			6,732		4.7
Market-based wholesale		60,682			96,498			(35,816	)	(37.1	)
Energy marketing		34,721			21,672			13,049		60.2
Transmission (a)		62,736			58,084			4,652		8.0
Other		19,747			16,500			3,247		19.7

Total Sales		1,262,592			1,189,201			73,391		6.2

OPERATING EXPENSES:
Fuel and purchased power		390,803			343,437			47,366		13.8
Operating and maintenance		344,095			322,767			21,328		6.6
Depreciation and amortization		148,240			127,682			20,558		16.1
Selling, general and administrative		119,174			124,723			(5,549	)	(4.4	)

Total Operating Expenses		1,002,312			918,609			83,703		9.1

INCOME FROM OPERATIONS		260,280			270,592			(10,312	)	(3.8	)

OTHER INCOME (EXPENSE):
Investment earnings		5,973			9,252			(3,279	)	(35.4	)
Other income		16,753			7,931			8,822		111.2
Other expense		(10,333	)		(13,102	)		2,769		21.1

Total Other Income		12,393			4,081			8,312		203.7

Interest expense		74,203			84,488			(10,285	)	(12.2	)

INCOME BEFORE INCOME TAXES		198,470			190,185			8,285		4.4
Income tax expense		46,233			62,218			(15,985	)	(25.7	)

NET INCOME		152,237			127,967			24,270		19.0
Preferred dividends		727			727			—		—

EARNINGS AVAILABLE FOR COMMON STOCK	$	151,510		$	127,240		$	24,270		19.1

BASIC EARNINGS PER SHARE	$	1.73		$	1.47		$	0.26		17.7

(a)

Transmission: Includes the SPP network transmission tariff. For the nine months ended September 30, 2006, our SPP network transmission costs were approximately $57.2 million. This amount, less approximately $7.3 million that was retained by the SPP as administration cost, was returned to us as revenue. For the nine months ended September 30, 2005, our SPP network transmission costs were approximately $49.5 million with an administration cost of approximately $3.9 million retained by the SPP.

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


	Nine Months Ended September 30,
	2006	2005	Change		% Change
	(Thousands of MWh)
Residential	5,059	5,001	58		1.2
Commercial	5,459	5,430	29		0.5
Industrial	4,386	4,130	256		6.2
Other retail	71	76	(5	)	(6.6	)

Total Retail	14,975	14,637	338		2.3
Tariff-based wholesale	4,094	4,183	(89	)	(2.1	)
Market-based wholesale	1,079	2,175	(1,096	)	(50.4	)

Total	20,148	20,995	(847	)	(4.0	)

The increase in retail sales reflects the change in rates, including the effect of implementing the RECA, and warmer weather. When measured by cooling degree days, the weather during the nine months ended September 30, 2006 was 2% warmer than during the same period last year and approximately 14% warmer than the 20-year average. The increase in industrial sales was due primarily to additional oil refinery load. The change in other retail sales reflects the recognition in the nine months ended September 30, 2006 of revenue subject to refund of which $10.4 million is due to the difference between estimated fuel and purchased power costs billed to our customers and actual fuel and purchased power costs incurred for our Westar Energy customers and $2.3 million is due to amounts associated with a transmission delivery charge that was approved in the 2005 KCC Order. The revenue subject to refund was partially offset by ceasing to accrue for rebates to customers in December 2005 due to the required accrual amounts having been reached.

Tariff-based sales made during the nine months ended September 30, 2006 were at an approximate 7% higher average price per MWh than during the same period of 2005. About $1.3 million, or 20%, of the increase in tariff-based wholesale sales is attributable to the operation of a fuel adjustment provision permitted in FERC tariffs. Reduced sales volumes partially offset the effect of higher prices. Sales volumes decreased due primarily to the decline in sales to a co-owner of Wolf Creek. We have an agreement with a co-owner of Wolf Creek to provide it with wholesale power during periods when Wolf Creek is out of service. While Wolf Creek was not out of service during the nine months ended September 30, 2006, during the second quarter of 2005, Wolf Creek was out of service for scheduled refueling and maintenance.

Market-based wholesale sales and sales volumes decreased due primarily to coal conservation efforts. The market-based sales we made during the nine months ended September 30, 2006 were at an approximate 27% higher average price per MWh than during the same period of 2005.

The increase in energy marketing reflects generally favorable contract valuations due primarily to favorable changes in market prices since we entered into the contracts.

The change in fuel and purchased power expense is the result of changing volumes produced and purchased, prevailing market prices, and contract provisions that allow for price changes. Since implementing the RECA, we no longer recognize in fuel expense the changes in the market value of certain fuel supply contracts, but instead record changes in the market value of these contracts as either a regulatory asset or a regulatory liability. During the nine months ended September 30, 2005, a period in which the RECA was not in effect, we recognized a reduction in fuel expense of $71.1 million associated with a non-cash mark-to-market gain on certain fuel supply contracts. Fuel used for generation during the nine months ended September 30, 2006 decreased $20.5 million because we burned approximately 6% less fuel due primarily to coal conservation efforts. In addition, during the nine months ended September 30, 2006, we deferred as a regulatory asset $1.3 million for the difference between the estimated fuel and purchased power costs that we billed our customers and our higher actual fuel and purchased power costs that we are allowed to collect under the terms of the RECA for our KGE customers. Purchased power expense decreased $1.4 million due primarily to a 10% decline in the average price per MWh.

Operating and maintenance expense increased due primarily to the amortization of $7.8 million of previously deferred storm restoration expense as authorized by the 2005 KCC Order, a $7.7 million increase in SPP network transmission costs, a $6.2 million increase in taxes other than income taxes due primarily to higher property taxes, increases in transmission and distribution expenses due primarily to higher materials costs and additional labor costs and an increase in maintenance expenses for outages at the La Cygne Generating Station and the Gordon Evans Energy Center. These higher expenses were partially offset by a $5.4 million reduction in the lease expense related to La Cygne Unit 2. Operating and maintenance expense in 2005 included a $3.5 million charge related to terminating development of a plant operating system at Wolf Creek.

Depreciation expense increased due primarily to the change in our depreciation rates. Our retail rates as authorized by the KCC provide for recovery of this increase.

Selling, general and administrative expense decreased due primarily to reduced legal fees associated with matters having to deal with former management and a decline in insurance costs. Higher employee benefit expenses, due primarily to increased pension and medical costs, partially offset the decrease.

Investment earnings decreased due primarily to a decrease in interest income and the cessation of the accrual of carrying costs for regulatory assets that we have now begun amortizing pursuant to the 2005 KCC Order. During the nine months ended September 30, 2005, we accrued $2.0 million of carrying costs on the regulatory assets related to the January 2002 and 2005 ice storms. In February 2006, we began amortizing the regulatory assets related to the two ice storms pursuant to the 2005 KCC Order and no longer accrue carrying costs. We also recorded $1.8 million interest income on our share of the proceeds related to the settlement of litigation involving Wolf Creek during the nine months ended September 30, 2005. We had no such interest income during the same period of 2006.

Other income increased due primarily to corporate-owned life insurance proceeds. Income received from corporate-owned life insurance was $15.5 million during the nine months ended September 30, 2006 and $5.9 million during the same period of 2005. Other expense decreased $2.8 million due primarily to the termination of an accounts receivable sales facility.

Interest expense on long-term debt decreased $12.9 million due primarily to a lower long-term debt balance and lower interest rates resulting from the refinancing activities discussed in detail in our 2005 Form 10-K in Note 10 of the Notes to Consolidated Financial Statements, “Long-term Debt.” Partially offsetting this decline was an increase of $4.8 million in interest expense on short-term debt due to increased borrowings under our revolving credit facility.

Income taxes for the interim periods presented are based on our estimate of the annual effective income tax rate and are adjusted for the effect of significant infrequent or unusual items. Our estimate of the annual effective income tax rate may differ from the statutory Federal income tax rate of 35% due to permanent differences between income for financial reporting purposes and income for tax reporting purposes, recognition or reversal of valuation allowances related to capital losses and net operating loss carry forwards and tax credits. The effective income tax rate was 23% for the nine months ended September 30, 2006 and 33% for the same period of 2005. The decrease in the effective tax rate is due primarily to the utilization of previously unrecognized capital loss carryforwards to offset realized capital gains, increases in non-taxable income from corporate-owned life insurance and the deduction for qualified domestic production activities, and the reversal of tax reserves as a result of a favorable re-evaluation of uncertain tax positions.

FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of September 30, 2006 compared to December 31, 2005.

Accounts receivable increased $71.0 million due primarily to the termination of an accounts receivable sales facility.

Inventories and supplies increased due primarily to planned increases in our coal and oil inventories.

The fair market value of our net energy marketing contracts decreased $84.4 million, to $33.5 million as of September 30, 2006, from $117.9 million as of December 31, 2005, due primarily to lower market valuations on our coal supply contract for Lawrence and Tecumseh Energy Centers.

Prepaid expenses increased due primarily to pre-payment of interest associated with our corporate-owned life insurance policies.

Other current assets decreased $42.2 million due primarily to the disbursement of the funds previously reserved for the settlement of lawsuits as discussed in detail in Note 8 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.”

Total restricted cash decreased due to the return of $26.0 million of collateral we had previously been required to post related to a capacity and transmission agreement. In May 2006, Moody’s Investors Service upgraded its credit ratings for our debt securities, which met conditions in the agreement that allowed the funds to be released.

Regulatory assets, net of regulatory liabilities, decreased to $270.8 million at September 30, 2006, from $275.0 million at December 31, 2005. Total regulatory assets decreased $48.4 million due primarily to changes in amounts due from customers for future income taxes and the amortization of previously deferred costs associated with the January 2002 and 2005 ice storms and other regulatory assets. Total regulatory liabilities decreased $44.2 million due primarily to the change in the market value of certain fuel supply contracts. As of September 30, 2006, we recorded a regulatory liability of $23.0 million compared with $117.7 million as of December 31, 2005 to recognize the cumulative mark-to-market adjustments associated with our coal supply contracts. This decline was partially offset by a $26.2 million increase in the nuclear decommissioning regulatory liability as discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations,” $10.4 million of revenue subject to refund and a $13.8 million increase in other regulatory liabilities.

As of September 30, 2006, we had no current maturities of long-term debt. Current maturities of long-term debt as of December 31, 2005 consisted of the $100.0 million outstanding aggregate principal amount of KGE 6.2% first mortgage bonds that we repaid in January 2006.

Short-term debt increased due to increased borrowings under the Westar Energy revolving credit facility. We used a portion of the borrowings to repay the KGE first mortgage bonds that were due in January 2006. In addition, we used borrowings under the revolving credit facility to meet on-going operational needs.

Other current liabilities decreased $41.3 million due primarily to the disbursement of the funds previously reserved for the settlement of lawsuits as discussed in detail in Note 8 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.” Further decreasing other current liabilities were the rebates we made to customers of $10.0 million during the nine months ended September 30, 2006.

Accrued employee benefits decreased due primarily to a $20.8 million voluntary contribution we made to our pension trust on March 21, 2006.

Asset retirement obligations decreased $46.7 million. For additional information, see Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations.”

Changes in temporary equity, paid-in capital and unearned compensation were due primarily to the implementation of SFAS No. 123R as discussed in detail in Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies – Stock Based Compensation.”

LIQUIDITY AND CAPITAL RESOURCES

Overview

We believe we will have sufficient cash to fund future operations, debt maturities and the payment of dividends from a combination of cash on hand, cash flows from operations and available borrowing capacity. Our available sources of funds include cash, the revolving credit facility and access to capital markets. Uncertainties affecting our ability to meet these cash requirements include, among others, factors affecting sales described in “– Operating Results” above, economic conditions, regulatory actions, conditions in the capital markets and compliance with environmental regulations.

Capital Resources

As of September 30, 2006, we had $9.1 million in unrestricted cash and cash equivalents. In addition, Westar Energy had $369.4 million available under its $500.0 million revolving credit facility against which $87.0 million had been borrowed and $43.6 million of letters of credit had been issued.

Debt Financings

On March 17, 2006, Westar Energy amended and restated the revolving credit facility dated May 6, 2005 to increase the size of the facility, extend its term and reduce borrowing costs. The amended and restated revolving credit facility matures on March 17, 2011. So long as there is no default or event of default under the revolving credit facility, we may elect to extend the term of the credit facility for up to an additional two years, subject to lender participation. The facility allows us to borrow up to an aggregate amount of $500.0 million, including letters of credit up to a maximum aggregate amount of $150.0 million. We may elect, subject to FERC approval, to increase the aggregate amount of borrowings under the facility to $750.0 million by increasing the commitment of one or more lenders who have agreed to such increase, or by adding one or more new lenders with the consent of the Administrative Agent and any letter of credit issuing bank, which will not be unreasonably withheld, so long as there is no default or event of default under the revolving credit facility.

On January 17, 2006, we repaid $100.0 million aggregate principal amount of 6.2% first mortgage bonds with cash on hand and borrowings under the revolving credit facility.

Credit Ratings

In May 2006, Moody’s Investors Service upgraded its credit ratings for our securities as shown in the table below and changed its outlook for our ratings to stable. In March 2006, Fitch Investors Service upgraded its credit ratings for our securities as shown in the table below and changed its outlook for our ratings to stable. Ratings with these agencies shown in the table below are as of October 15, 2006.


	Westar Energy Mortgage Bond Rating	Westar Energy Unsecured Debt	KGE Mortgage Bond Rating
Standard & Poor’s Ratings Group	BBB-	BB-	BBB
Moody’s Investors Service	Baa2	Baa3	Baa2
Fitch Investors Service	BBB	BBB-	BBB

Cash Flows from Operating Activities

Operating activities provided $156.6 million of cash in the nine months ended September 30, 2006 compared with $246.8 million of cash during the same period of 2005. The decrease in cash flows from operating activities was due to the termination of our accounts receivable sales program, a $61.4 million increase in income tax payments and a $20.8 million voluntary contribution to our pension trust. During the nine months ended September 30, 2005, we used $33.2 million for system restoration costs related to an ice storm that affected our service territory in January 2005 and approximately $14.2 million for the Wolf Creek refueling outage. Also during the nine months ended September 30, 2005, we received approximately $55.7 million from income tax refunds and $25.0 million from the sale of accounts receivable.

Cash Flows used in Investing Activities

The utility business is capital intensive and requires significant investment in plant on an annual basis. We spent $200.4 million in the nine months ended September 30, 2006 and $145.9 million in the same period of 2005 on net additions to utility property, plant and equipment, which included construction of environmental upgrades at La Cygne during 2006 and costs associated with the refueling outage at Wolf Creek during 2005. During the nine months ended September 30, 2006, we received $9.5 million from investments in corporate-owned life insurance, $23.2 million from investments in Guardian and $26.0 million from the return of funds previously restricted. During the nine months ended September 30, 2005, we received proceeds from our investment in corporate-owned life insurance of $10.8 million and proceeds from the settlement of litigation involving Wolf Creek of $6.8 million. We used $4.8 million for system restoration costs that were capitalized related to the January 2005 ice storm.

Cash Flows used in Financing Activities

We used $26.3 million cash for financing activities in the nine months ended September 30, 2006, compared with $109.2 million in the same period of 2005. In the nine months ended September 30, 2006, we used cash primarily to retire long-term debt, repay corporate-owned life insurance borrowings and pay dividends. Short-term debt borrowings provided $87.0 million, long-term debt issuances provided $99.7 million and borrowings from corporate-owned life insurance provided $58.4 million. In the nine months ended September 30, 2005, we used cash primarily to retire long-term debt and pay dividends. We received cash primarily from the issuance of long-term debt and borrowings from corporate-owned life insurance.

Future Cash Requirements

On August 22, 2006, we announced our intention to build a new natural gas fired peaking plant, with the initial 300 MW expected to begin operation in the summer of 2008. As work on this site progresses, we will incur costs beginning in 2006 and continuing through the completion of the project. This plant will require significantly more capital expenditures than what had previously been planned in our 2005 Form 10-K, which discloses anticipated capital expenditures for additional generating capacity in 2007 and 2008 of $16.4 million and $63.8 million, respectively. These amounts were based substantially on plans to add 150 megawatts of peaking capacity in the summer of both 2008 and 2009. Based on our current plans, we now anticipate capital expenditures for additional generating capacity in 2007 and 2008 of $170.3 million and $142.9 million, respectively.

OFF-BALANCE SHEET ARRANGEMENTS

In March 2006, we terminated an accounts receivable sales program. For additional information, see our 2005 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2005 through September 30, 2006, there have been no material changes outside the ordinary course of business in our contractual obligations and commercial commitments. For additional information, see our 2005 Form 10-K.

OTHER INFORMATION

Purchase of Electric Generation Facility

On October 31, 2006, we finalized the purchase of a 300 MW electric generation facility from ONEOK Energy Services Company, L.P. for $53.0 million. The agreement requires us to assume a capacity sale agreement for 75 MW through 2015.

Asset Retirement Obligations

In September, 2006, we revised our estimate of the timing of cash flows related to the decommissioning of Wolf Creek and adjusted our related ARO. For additional information, see Note 12 of the Notes to Condensed Consolidated Financial Statements, “Asset Retirement Obligations.”

Stock Based Compensation

Effective January 1, 2006, we adopted SFAS No. 123R using the modified prospective transition method. Since 2002, we have used RSUs exclusively for our stock-based compensation awards. Given the characteristics of our stock-based compensation awards, the adoption of SFAS No. 123R did not have a material impact on our consolidated results of operations.

Pension Obligation

On March 21, 2006, we made a voluntary contribution to the pension trust of $20.8 million. In August 2006, the Pension Protection Act of 2006 (PPA) became law. The PPA requires changes to the method of valuing pension plan assets and liabilities for funding purposes, as well as the minimum funding levels required by 2008. We are currently evaluating what impact the PPA may have on our consolidated financial statements.

Customer Rebates

During the nine months ended September 30, 2006 and 2005, we made rebates to customers of $10.0 million and $10.5 million, respectively, in accordance with a July 25, 2003 KCC Order.

Real-Time Energy Imbalance Market

As discussed in our 2005 Form 10-K, the SPP is required by FERC to implement a real-time energy imbalance market. An energy imbalance exists when a market participant’s actual power inputs or consumption to or from the grid differ from the market participant’s expected power inputs or consumption. The intent of a real-time market system is to permit efficient balancing of energy production and consumption by facilitating a real time energy market. The SPP board and members continue to evaluate market operations and do not anticipate beginning market operations before February 1, 2007. At such time that market operations begin, energy imbalances will be financially settled. At this time, we are unable to determine when market operation will begin and what impact this may have on our results of operations.

Fair Value of Energy Marketing Contracts

The tables below show the fair value of energy marketing and fuel contracts that were outstanding as of September 30, 2006, their sources and maturity periods.


	Fair Value of Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2005	$	117,929
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		(32,676	)
Changes in fair value of contracts outstanding at the beginning and end of the period		(58,024	)
Fair value of new contracts entered into during the period		6,305

Fair value of contracts outstanding as of September 30, 2006 (a)	$	33,534

(a)

Approximately $23.0 million of the fair value of fuel supply contracts is recognized as a regulatory liability.

The sources of the fair values of the financial instruments related to these contracts as of September 30, 2006 are summarized in the following table.


	Fair Value of Contracts at End of Period
Sources of Fair Value	Total Fair Value		Maturity Less Than 1 Year		Maturity 1-3 Years		Maturity 4-5 Years
	(In Thousands)
Prices actively quoted (futures)	$	1	$	1	$	—	$	—
Prices provided by other external sources (swaps and forwards)		20,941		13,385		6,734		822
Prices based on option pricing models (options and other) (a)		12,592		2,906		8,528		1,158

Total fair value of contracts outstanding	$	33,534	$	16,292	$	15,262	$	1,980

(a)	Options are priced using a series of techniques, such as the Black option pricing model.

New Accounting Pronouncements

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, FASB released SFAS No. 158. Under the new standard, companies must recognize a net liability or asset to report the funded status of their defined benefit pension and other postretirement benefit plans on their balance sheets. The recognition and disclosure provisions of SFAS No. 158 are required to be adopted as of December 31, 2006. We are still evaluating the final impact this standard will have on our consolidated financial statements, but believe at this time that it will decrease equity by approximately $90.0 million, net of tax. We are pursuing regulatory authority to allow us to recognize this item as a regulatory asset pursuant to SFAS No. 71, rather than as a charge to equity. The actual impact of the adoption of SFAS No. 158 could differ significantly from this estimate due to plan asset performance for the year, the discount rates in effect when plan liabilities are measured and regulatory treatment.

SFAS No. 157 – Fair Value Measurements

In September 2006, FASB released SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We anticipate adopting the guidance effective January 1, 2008. We are currently evaluating what impact the adoption of SFAS No. 157 will have on our consolidated financial statements.

SAB No. 108 – Effects of Prior Year Misstatements on Current Year Financial Statements

In September 2006, the staff of the SEC released SAB No. 108, which provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of either (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). The guidance provided in SAB No. 108 requires both methods to be used in quantifying a misstatement. This guidance should be applied to annual financial statements for fiscal years ending after November 15, 2006. The cumulative effect of the change in method of quantifying errors, if any, can be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year with the offsetting adjustment made to the opening balance of retained earnings for that year. Alternatively, a company may restate prior periods. SAB No. 108 requires disclosure of the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. We are currently evaluating the effect this bulletin will have on our consolidated financial statements, but believe it will not have an impact.

FIN 48 – Accounting for Uncertainty in Income Taxes

In July 2006, FASB released FIN 48, which prescribes a comprehensive model for how companies should recognize, measure and disclose in their financial statements uncertain tax positions taken, or expected to be taken, on a tax return. It also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006 with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. We anticipate adopting the guidance effective January 1, 2007. We are currently evaluating what impact the adoption of FIN 48 will have on our consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of September 30, 2006, exposure to interest rate risk increased as discussed below. No other significant changes have occurred in our exposure to market risk from December 31, 2005 through September 30, 2006. For additional information, see our 2005 Form 10-K, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Interest Rate Exposure

From December 31, 2005 to September 30, 2006, variable rate debt and current maturities of fixed rate debt increased $37.0 million. A 100 basis point change in interest rates applicable to each of these instruments would impact income before income taxes on an annualized basis by approximately $3.6 million. This represents an increase in our exposure to interest rate risk on an annualized basis of approximately $1.3 million, from $2.3 million as of December 31, 2005.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of management, including our chief executive officer and our chief financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and our subsidiaries is communicated to the chief executive officer and the chief financial officer. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of September 30, 2006, our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the chief executive officer and the chief financial officer, and recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no changes in our internal controls over financial reporting during the three months ended September 30, 2006 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

Information on other legal proceedings is set forth in Notes 3, 7, 8, 9 and 10 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies – EPA New Source Review,” “Legal Proceedings,” “Ongoing Investigations – Department of Labor Investigation,” and “Potential Liabilities to David C. Wittig and Douglas T. Lake,” respectively, which are incorporated herein by reference.

ITEM 1A. RISK FACTORS

There were no material changes in our risk factors from December 31, 2005 through September 30, 2006. For additional information, see our 2005 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS


31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 2006

31(b)		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended September 30, 2006

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended September 30, 2006 (furnished and not to be considered filed as part of the Form 10-Q)

SIGNATURE

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


	WESTAR ENERGY, INC.

Date: November 3, 2006	By:	/s/ Mark A. Ruelle
		Mark A. Ruelle, Executive Vice President and Chief Financial Officer

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents