Edgar Filing: WESTAR ENERGY INC /KS

Carrying Value

Fair Value

(In Thousands)

Fixed-rate debt, net of current maturities

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 June 30, 2009

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

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

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

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


Common Stock, par value $5.00 per share		108,857,990 shares
(Class)		(Outstanding at July 30, 2009)

TABLE OF CONTENTS


		Page
PART I. Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited)

	Consolidated Balance Sheets	6

	Consolidated Statements of Income	7

	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	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

Item 4.	Controls and Procedures	40

PART II. Other Information

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

Item 3.	Defaults Upon Senior Securities	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	41

Item 6.	Exhibits	42

Signature		43

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Form 10-Q are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:

•

amount, type and timing of capital expenditures,

•

earnings,

•

cash flow,

•

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,

•

regulatory matters,

•

nuclear operations, and

•

the overall economy of our service area and its impact on our customers’ demand for electricity and their ability to pay for service.

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

•

regulated and competitive markets,

•

economic and capital market conditions, including the impact of changes in interest rates and the cost and availability of capital,

•

inflation,

•

execution of our planned capital expenditure program,

•

performance of our generating plants,

•

changes in accounting requirements and other accounting matters,

•

changing weather,

•

the impact of the formation of regional transmission organizations and independent system operators such as the Southwest Power Pool, including changes in the energy markets in which we participate resulting from the development and implementation of real time and next day trading markets, and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations and independent system operators,

•

the impact of economic changes and downturns in the energy industry and the market for trading wholesale energy, including counterparty performance,

•

the outcome of the lawsuit filed by the Department of Justice on behalf of the Environmental Protection Agency on February 4, 2009, alleging violations of the Federal Clean Air Act, and developments related to environmental matters including possible future legislative or regulatory mandates related to emissions of gases or substances, including what are now referred to as greenhouse gases,

•

political, legislative, judicial and regulatory developments at the municipal, state and federal level that can affect us or our industry, including in particular those relating to environmental laws,

•

the impact of our potential liability to former executive officers for unpaid compensation and the impact of claims they have made against us related to the termination of their employment,

•

the outcome of the Federal Energy Regulatory Commission non-public investigation of our use of transmission service within the Southwest Power Pool,

•

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 invested plan assets,

•

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

•

the impact of adverse changes in market conditions potentially resulting in the need for additional funding for the nuclear decommissioning and pension trusts,

•

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

•

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

•

homeland and information security considerations,

•

coal, natural gas, uranium, diesel, oil and wholesale electricity prices,

•

cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business, 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, 2008. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our operations and financial results may be included in our Annual Report on Form 10-K for the year ended December 31, 2008. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.


Abbreviation or Acronym		Definition
2008 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2008
AFUDC		Allowance for Funds Used During Construction
CO₂		Carbon dioxide
Codification		FASB Accounting Standards Codification
COLI		Corporate-owned life insurance
DOJ		Department of Justice
EPA		Environmental Protection Agency
EPS		Earnings per share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Investors Service
GAAP		Generally Accepted Accounting Principles
IRS		Internal Revenue Service
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
kV		Kilovolt
MMBtu		Millions of British Thermal Units
Moody’s		Moody’s Investors Service
MWh		Megawatt hours
OTC		Over-the-counter
RECA		Retail energy cost adjustment
RSUs		Restricted share units
S&P		Standard & Poor’s Ratings Group
SEC		Securities and Exchange Commission
SPP		Southwest Power Pool
Wolf Creek		Wolf Creek Generating Station

PART I. FINANCIAL INFORMATION

ITEM 1.

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands)

(Unaudited)


	June 30, 2009		December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,941	$	22,914
Accounts receivable, net of allowance for doubtful accounts of $4,310 and $4,810, respectively		240,478		199,116
Inventories and supplies, net		206,904		204,297
Energy marketing contracts		106,189		131,647
Taxes receivable		65,324		36,462
Deferred tax assets		15,613		16,416
Prepaid expenses		11,682		33,419
Regulatory assets		71,116		79,783
Other		18,024		19,077

Total Current Assets		740,271		743,131

PROPERTY, PLANT AND EQUIPMENT, NET		5,708,556		5,533,521

OTHER ASSETS:
Regulatory assets		834,790		872,487
Nuclear decommissioning trust		94,425		85,555
Energy marketing contracts		10,058		25,601
Other		212,232		182,964

Total Other Assets		1,151,505		1,166,607

TOTAL ASSETS	$	7,600,332	$	7,443,259

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	146,394	$	146,366
Short-term debt		62,700		174,900
Accounts payable		151,531		195,683
Accrued taxes		49,555		44,008
Energy marketing contracts		110,103		104,622
Accrued interest		48,381		42,142
Regulatory liabilities		23,852		31,123
Other		137,909		133,565

Total Current Liabilities		730,425		872,409

LONG-TERM LIABILITIES:
Long-term debt, net		2,491,428		2,192,538
Obligation under capital leases		108,395		117,909
Deferred income taxes		1,035,304		1,004,920
Unamortized investment tax credits		58,036		59,386
Deferred gain from sale-leaseback		111,279		114,027
Accrued employee benefits		510,190		526,177
Asset retirement obligations		97,055		95,083
Energy marketing contracts		3,186		2,262
Regulatory liabilities		95,789		91,934
Other		124,149		155,612

Total Long-Term Liabilities		4,634,811		4,359,848

COMMITMENTS AND CONTINGENCIES (see Notes 7 and 8)
TEMPORARY EQUITY		3,434		3,422

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 and outstanding 108,722,335 shares and 108,311,135 shares, respectively		543,612		541,556
Paid-in capital		1,332,302		1,326,391
Retained earnings		334,312		318,197

Total Shareholders’ Equity		2,231,662		2,207,580

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,600,332	$	7,443,259

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 June 30,
	2009			2008
SALES	$	467,812		$	451,219

OPERATING EXPENSES:
Fuel and purchased power		120,508			191,355
Operating and maintenance		139,810			130,966
Depreciation and amortization		63,814			49,605
Selling, general and administrative		53,638			44,254

Total Operating Expenses		377,770			416,180

INCOME FROM OPERATIONS		90,042			35,039

OTHER INCOME (EXPENSE):
Investment earnings		5,322			1,788
Other income		1,153			4,343
Other expense		(2,341	)		(2,327	)

Total Other Income		4,134			3,804

Interest expense		40,094			30,311

INCOME FROM OPERATIONS BEFORE INCOME TAXES		54,082			8,532
Income tax expense		15,696			2,687

NET INCOME		38,386			5,845
Preferred dividends		242			242

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	38,144		$	5,603

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (See Note 2)	$	0.35		$	0.06

Average equivalent common shares outstanding		109,538,854			100,733,815
DIVIDENDS DECLARED PER COMMON SHARE	$	0.30		$	0.29

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)


	Six Months Ended June 30,
	2009			2008
SALES	$	889,579		$	858,046

OPERATING EXPENSES:
Fuel and purchased power		261,152			337,804
Operating and maintenance		261,978			246,984
Depreciation and amortization		122,028			98,501
Selling, general and administrative		101,619			85,910

Total Operating Expenses		746,777			769,199

INCOME FROM OPERATIONS		142,802			88,847

OTHER INCOME (EXPENSE):
Investment earnings		4,530			84
Other income		4,410			10,160
Other expense		(6,903	)		(6,661	)

Total Other Income		2,037			3,583

Interest expense		75,170			41,001

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		69,669			51,429
Income tax expense (benefit)		20,098			(15,552	)

INCOME FROM CONTINUING OPERATIONS		49,571			66,981
Results of discontinued operations, net of tax		32,978			—

NET INCOME		82,549			66,981
Preferred dividends		485			485

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	82,064		$	66,496

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING (See Note 2):
Earnings available from continuing operations	$	0.45		$	0.67
Discontinued operations, net of tax		0.30			—

Earnings per common share, basic and diluted	$	0.75		$	0.67

Average equivalent common shares outstanding		109,435,488			99,074,840
DIVIDENDS DECLARED PER COMMON SHARE	$	0.60		$	0.58

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)


	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	82,549		$	66,981
Discontinued operations, net of tax		(32,978	)		—
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		122,028			98,501
Amortization of nuclear fuel		8,602			5,498
Amortization of deferred gain from sale-leaseback		(2,748	)		(2,747	)
Amortization of prepaid corporate-owned life insurance		10,238			7,760
Non-cash compensation		2,720			2,571
Net changes in energy marketing assets and liabilities		6,434			10,363
Accrued liability to certain former officers		312			(937	)
Net deferred income taxes and credits		32,045			27,942
Stock based compensation excess tax benefits		(269	)		(378	)
Allowance for equity funds used during construction		(3,277	)		(9,199	)
Changes in working capital items, net of acquisitions and dispositions:
Accounts receivable		(41,362	)		(51,437	)
Inventories and supplies		(2,607	)		(19,074	)
Prepaid expenses and other		(341	)		(69,526	)
Accounts payable		(21,330	)		(16,086	)
Accrued taxes		10,207			14,903
Other current liabilities		67,866			(13,685	)
Changes in other assets		16,589			(4,983	)
Changes in other liabilities		(38,692	)		(48,621	)

Cash flows from (used in) operating activities		215,986			(2,154	)

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(338,768	)		(419,883	)
Investment in corporate-owned life insurance		(17,724	)		(18,720	)
Purchase of securities within the nuclear decommissioning trust fund		(22,538	)		(164,634	)
Sale of securities within the nuclear decommissioning trust fund		21,145			163,639
Proceeds from investment in corporate-owned life insurance		1,216			533
Other investing activities		1,300			995

Cash flows used in investing activities		(355,369	)		(438,070	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		(112,200	)		(800	)
Proceeds from long-term debt		297,507			152,023
Retirements of long-term debt		(802	)		(608	)
Repayment of capital leases		(9,013	)		(9,049	)
Borrowings against cash surrender value of corporate-owned life insurance		7,547			61,628
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(3,151	)		(1,464	)
Stock based compensation excess tax benefits		269			378
Issuance of common stock, net		2,181			291,833
Cash dividends paid		(60,928	)		(50,472	)

Cash flows from financing activities		121,410			443,469

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(17,973	)		3,245
CASH AND CASH EQUIVALENTS:
Beginning of period		22,914			5,753

End of period	$	4,941		$	8,998

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 684,000 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. We evaluated subsequent events up to the time we issued our condensed consolidated financial statements on August 6, 2009.

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

Use of Management’s Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, investments, valuation of our energy marketing portfolio, intangible assets, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and other post-retirement and post-employment benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three and six months ended June 30, 2009, are not necessarily indicative of the results to be expected for the full year.

Allowance for Funds Used During Construction

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In Thousands)
Borrowed funds	$	717	$	5,142	$	2,846	$	10,687
Equity funds		722		3,819		3,277		9,199

Total	$	1,439	$	8,961	$	6,123	$	19,886

Average AFUDC Rates		3.2%		5.7%		4.7%		6.5%

Earnings Per Share

Effective January 1, 2009, we adopted guidance issued by the Financial Accounting Standards Board (FASB) for determining whether instruments granted in share-based payment transactions are participating securities. According to the provisions of this guidance, we have participating securities related to unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends as declared on an equal basis with common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS). This guidance was adopted with retrospective application to prior periods and resulted in no change to our previously reported EPS for the three and six months ended June 30, 2008.

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(Dollars In Thousands, Except Per Share Amounts)
Income from continuing operations	$	38,386	$	5,845	$	49,571	$	66,981
Less: Preferred dividends		242		242		485		485
Income from continuing operations allocated to RSUs		154		47		224		552

Income from continuing operations attributable to common stock	$	37,990	$	5,556	$	48,862	$	65,944

Weighted average equivalent common shares outstanding – basic		109,538,854		100,733,815		109,435,488		99,074,840
Effect of dilutive securities:
Employee stock options		339		807		368		822

Weighted average equivalent common shares outstanding – diluted (a)		109,539,193		100,734,622		109,435,856		99,075,662

Earnings from continuing operations per common share, basic and diluted	$	0.35	$	0.06	$	0.45	$	0.67

(a)	For the three and six months ended June 30, 2009, we did not have any antidilutive shares. For the three and six months ended June 30, 2008, potentially dilutive shares not included in the denominator because they are antidilutive totaled 21,300 shares.

Supplemental Cash Flow Information


	Six Months Ended June 30,
	2009			2008
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	67,484		$	50,246
Income taxes, net of refunds		(9,063	)		600
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		41,927			84,054
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and RSUs		5,409			7,460
Assets acquired through capital leases		1,178			2,503

New Accounting Pronouncements

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

FASB Codification

In June 2009, FASB approved its Accounting Standards Codification (Codification) as the exclusive authoritative reference for U.S. GAAP to be applied by nongovernmental entities. Under the Codification, with the exception of a small change in revenue recognition guidance, existing U.S. GAAP did not change. In addition, Securities and Exchange Commission (SEC) rules and interpretive releases are still considered authoritative GAAP for SEC registrants. The Codification, which changes the referencing of accounting standards, is effective for interim and annual reporting periods ending after September 15, 2009. We adopted the Codification effective July 1, 2009, without a material impact on our consolidated financial statements.

Variable Interest Entities

In June 2009, FASB issued guidance that changes the approach to determining a variable interest entity’s primary beneficiary and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. This guidance is effective for annual reporting periods beginning after November 15, 2009. We are currently evaluating what impact the adoption of this guidance will have on our consolidated financial statements.

Subsequent Events

In May 2009, FASB issued guidance on subsequent events that sets forth the period after the balance sheet date during which a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This guidance is effective for interim or annual financial periods ending after June 15, 2009. We adopted this guidance without a material impact on our consolidated financial statements.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, FASB issued guidance that changes how other-than-temporary impairments of investments in debt securities are recognized and measured. The guidance also provides for changes in the presentation and disclosure requirements surrounding other-than-temporary impairments of investments in debt and equity securities. This guidance is effective for interim and annual reporting periods ending after June 15, 2009. We adopted this guidance effective April 1, 2009, without a material impact on our consolidated financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, FASB issued guidance that requires enhanced disclosures about the plan assets of defined benefit pension and other postretirement benefit plans. These disclosures include how investment allocation decisions are made, the factors pertinent to understanding investment policies and strategies, the fair value of each major category of plan assets for pension plans and other postretirement benefit plans separately, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets and significant concentrations of risk within plan assets. This guidance is effective for fiscal years ending after December 15, 2009. We are currently evaluating what impact the adoption of this guidance will have on our consolidated financial statements.

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, FASB issued guidance for determining whether instruments granted in share-based payment transactions are participating securities. The guidance provides that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. This guidance is effective for fiscal years beginning after December 15, 2008, with retrospective application to prior periods. We adopted this guidance effective January 1, 2009. See “—Earnings Per Share” above for additional information.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, FASB issued guidance that requires expanded disclosure to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. The guidance amends and expands the disclosure requirements related to derivative instruments and hedging activities by requiring qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosure about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This guidance is effective for fiscal years beginning after November 15, 2008. We adopted this guidance effective January 1, 2009. See Note 3, “Financial and Derivative Instruments, Energy Marketing and Risk Management,” for additional information.

Fair Value Measurements

In September 2006, FASB issued guidance that defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. This guidance is effective for fiscal years beginning after November 15, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. In February 2008, FASB issued additional guidance that delays the effective date of the aforementioned guidance for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The non-financial items subject to the deferral include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. We adopted the guidance for financial assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. We adopted the guidance for non-financial assets and liabilities recognized at fair value on a non-recurring basis effective January 1, 2009. The adoption of this guidance did not have a material impact on our consolidated financial statements. See Note 3, “Financial and Derivative Instruments, Energy Marketing and Risk Management,” for additional information.

In April 2009, FASB issued guidance on two separate fair value issues. Both of the releases are effective for interim and annual reporting periods ending after June 15, 2009, and we adopted both of them effective April 1, 2009. One of the releases provides guidance for determining fair value when the volume and level of activity for an asset or liability have significantly decreased and for identifying transactions that are not orderly. We adopted this guidance without a material impact on our consolidated financial statements. The other release requires disclosures about the fair value of financial instruments in interim reporting periods as well as in annual financial statements. See Note 3, “Financial and Derivative Instruments, Energy Marketing and Risk Management,” for additional information.

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

Values of Financial and Derivative Instruments

We carry cash and cash equivalents, short-term borrowings and variable-rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed-rate debt based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.

Most of our investments in equity, debt and commodity instruments are recorded at fair value using quoted market prices or valuation models utilizing observable market data when available. A portion of our investments is comprised of private equity investments, debt or real estate securities that require significant unobservable market information to measure the fair value of the investments. The fair value of private equity investments is initially measured at cost or at the value derived from subsequent financing with adjustments when actual performance differs significantly from expected performance; when market, economic or company-specific conditions change; or when other news or events have a material impact on the security. Debt investments for which we apply unobservable information to measure fair value are principally invested in mortgage-backed securities and collateralized loans. These investments are measured at fair value using subjective estimates such as projected cash flows and interest rates. Real estate securities are measured at fair value using market discount rates, projected cash flows and the estimated value into perpetuity.

Energy marketing contracts can be exchange-traded or over-the-counter (OTC). Fair value measurements of exchange-traded contracts typically utilize quoted prices in active markets. OTC contracts are valued using market transactions and other market evidence whenever possible, including market-based inputs to models, model calibration to market clearing transactions or alternative pricing sources with reasonable levels of price transparency. Valuation models require a variety of inputs, including contractual terms, market prices, yield curves, credit curves, measures of volatility and correlations of such inputs. Certain OTC contracts trade in less liquid markets with limited pricing information and the determination of fair value for these derivatives is inherently more subjective. In these situations, management estimations are a significant input. See “—Recurring Fair Value Measurements” and “—Derivative Instruments” below for additional information.

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our financial instruments as of June 30, 2009.

Recurring Fair Value Measurements

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


	Level 1		Level 2		Level 3		Total
	(In Thousands)
As of June 30, 2009
Assets:
Energy Marketing Contracts	$	10,568	$	65,838	$	39,841	$	116,247
Nuclear Decommissioning Trust:
Equity securities		36,197		24,744		1,791		62,732
Debt securities		14,324		6,083		4,684		25,091
Real estate securities		—		—		3,930		3,930
Commodities		1,666		—		—		1,666
Cash equivalents		1,006		—		—		1,006

Total Nuclear Decommissioning Trust		53,193		30,827		10,405		94,425

Trading Securities:
Equity securities		—		18,994		—		18,994
Debt securities		—		—		10,211		10,211

Total Trading Securities		—		18,994		10,211		29,205

Total Assets Measured at Fair Value	$	63,761	$	115,659	$	60,457	$	239,877

Liabilities:
Energy Marketing Contracts	$	10,879	$	65,203	$	37,207	$	113,289

As of December 31, 2008
Assets:
Energy Marketing Contracts	$	1,600	$	104,821	$	50,827	$	157,248
Nuclear Decommissioning Trust:
Equity securities		31,875		20,511		2,006		54,392
Debt securities		12,622		10,013		—		22,635
Real estate securities		—		—		6,028		6,028
Commodities		1,459		—		—		1,459
Cash equivalents		1,041		—		—		1,041

Total Nuclear Decommissioning Trust		46,997		30,524		8,034		85,555

Trading Securities (a):
Equity securities		13,420		—		—		13,420
Debt securities		—		9,503		—		9,503

Total Trading Securities		13,420		9,503		—	$	22,923

Total Assets Measured at Fair Value	$	62,017	$	144,848	$	58,861	$	265,726

Liabilities:
Energy Marketing Contracts	$	1,594	$	99,004	$	6,286	$	106,884


(a) Does not include cash and cash equivalents recorded at cost.

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of June 30, 2009, we have recorded $2.2 million for our right to reclaim cash collateral and $1.9 million for our obligation to return cash collateral. As of December 31, 2008, we had recorded $5.1 million for our right to reclaim cash collateral and $4.5 million for our obligation to return cash collateral.

The following table provides a reconciliation of assets and liabilities measured at fair value using significant level 3 inputs for the three and six months ended June 30, 2009.


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Debt		Net Balance
	Energy Marketing Contracts, net			Equity			Debt		Real Estate Securities			Trading Securities Debt		Net Balance
	(In Thousands)
Balance as of March 31, 2009	$	5,663		$	1,736		$	—	$	4,828		$	—	$	12,227
Total realized and unrealized gains (losses) included in:
Earnings (a)		(758	)		—			—		—			672		(86	)
Regulatory assets		(2,045	)(b)		—			—		—			—		(2,045	)
Regulatory liabilities		(286	)(b)		(65	)		387		(898	)		—		(862	)
Purchases, issuances and settlements		60			120			—		—			9,539		9,719
Transfers in/out		—			—			4,297		—			—		4,297

Balance as of June 30, 2009	$	2,634		$	1,791		$	4,684	$	3,930		$	10,211	$	23,250


Balance as of December 31, 2008	$	44,541		$	2,006		$	—	$	6,028		$	—		52,575
Total realized and unrealized gains (losses) included in:
Earnings (a)		814			—			—		—			672		1,486
Regulatory assets		(25,104	)(b)		—			—		—			—		(25,104	)
Regulatory liabilities		(10,708	)(b)		(335	)		387		(2,098	)		—		(12,754	)
Purchases, issuances and settlements		(6,909	)		120			—		—			9,539		2,750
Transfers in/out		—			—			4,297		—			—		4,297

Balance as of June 30, 2009	$	2,634		$	1,791		$	4,684	$	3,930		$	10,211	$	23,250

(a)	Unrealized and realized gains and losses included in earnings resulting from energy marketing activities are reported in sales. Unrealized and realized gains and losses resulting from trading securities are included in other income.

(b)	Includes changes in the fair value of certain fuel supply and electricity sale contracts.

The following table provides a reconciliation of assets and liabilities measured at fair value using significant level 3 inputs for the three and six months ended June 30, 2008.


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust				Net Balance
	Energy Marketing Contracts, net			Equity		Real Estate Securities		Net Balance
	(In Thousands)
Balance as of March 31, 2008	$	60,431		$	1,566	$	—	$	61,997
Total realized and unrealized gains (losses) included in:
Earnings (a)		(6,578	)		—		—		(6,578	)
Regulatory liabilities (b)		27,099			—		—		27,099
Purchases, issuances and settlements		(2,568	)		40		6,000		3,472
Transfers in/out		(235	)		—		—		(235	)

Balance as of June 30, 2008	$	78,149		$	1,606	$	6,000	$	85,755


Balance as of January 1, 2008	$	41,141		$	1,251	$	—	$	42,392
Total realized and unrealized gains (losses) included in:
Earnings (a)		(9,905	)		—		—		(9,905	)
Regulatory liabilities (b)		52,298			—		—		52,298
Purchases, issuances and settlements		(5,150	)		355		6,000		1,205
Transfers in/out		(235	)		—		—		(235	)

Balance as of June 30, 2008	$	78,149		$	1,606	$	6,000	$	85,755



(a) Unrealized and realized gains and losses included in earnings are reported in sales. (b) Includes changes in the fair value of certain fuel supply and electricity sale contracts.

A portion of the gains and losses contributing to changes in net assets in the above tables is unrealized. The following tables summarize the unrealized gains and losses we recorded on our consolidated financial statements during the three and six months ended June 30, 2009 and 2008, attributed to level 3 assets and liabilities still held as of June 30, 2009 and 2008, respectively.


	Three Months Ended June 30, 2009
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Debt		Net Balance
	Energy Marketing Contracts, net			Equity			Debt		Real Estate Securities			Trading Securities Debt		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(38	)	$	—		$	—	$	—		$	672	$	634
Regulatory assets		2,182	(b)		—			—		—			—		2,182
Regulatory liabilities		(1,307	) (b)		(65	)		387		(898	)		—		(1,883	)

Total	$	837		$	(65	)	$	387	$	(898	)	$	672	$	933


	Six Months Ended June 30, 2009
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Debt		Net Balance
	Energy Marketing Contracts, net			Equity			Debt		Real Estate Securities			Trading Securities Debt		Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(426	)	$	—		$	—	$	—		$	672	$	246
Regulatory assets		(9,821	)(b)		—			—		—			—		(9,821	)
Regulatory liabilities		(21,659	)(b)		(335	)		387		(2,098	)		—		(23,705	)

Total	$	(31,906	)	$	(335	)	$	387	$	(2,098	)	$	672	$	(33,280	)

(a)	Unrealized gains and losses included in earnings resulting from energy marketing activities are reported in sales.

Unrealized gains and losses resulting from trading securities are reported in other income.

(b)	Includes changes in the fair value of certain fuel supply and electricity sale contracts.


	Energy Marketing Contracts, net
	Three Months Ended June 30, 2008			Six Months Ended June 30, 2008
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(5,031	)	$	(6,251	)
Regulatory liabilities (b)		26,056			50,058

Total	$	21,025		$	43,807



(a) Unrealized gains and losses included in earnings are reported in sales. (b) Regulatory liabilities include changes in the fair value of certain fuel supply and electricity sale contracts.

Derivative Instruments

We are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates that could affect our consolidated financial statements. We manage our exposure to these market risks through our regular operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments. We use the term economic hedge to mean a strategy intended to manage risks of volatility in prices or rate movements on selected assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to offset the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. We do not hold derivative instruments that are designated as hedging instruments.

We engage in both financial and physical trading to increase profits, manage our commodity price risk and enhance system reliability. Within our energy trading portfolio, we may establish certain positions intended to economically hedge a portion of physical sale or purchase contracts and we may enter certain positions attempting to take advantage of market trends and conditions. We use financial instruments to help us manage our contractual commitments, reduce our exposure to changes in market prices and take advantage of opportunities in the energy markets. As of June 30, 2009, we had under contract the following energy-related products.


	Unit of Measure	Net Quantity
Electricity	MWh	4,455,746
Natural Gas	MMBtu	3,087,500
Coal	Tons	5,625,000

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

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

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

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

The following table presents the fair value of derivative instruments reflected on our consolidated balance sheet.

Commodity Derivatives Not Designated as Hedging Instruments as of June 30, 2009


Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In Thousands)			(In Thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	106,189	Energy marketing contracts	$	110,103
Other assets:			Other liabilities:
Energy marketing contracts		10,058	Energy marketing contracts		3,186

Total	$	116,247	Total	$	113,289

The following table presents how changes in the fair value of commodity derivative instruments affected our consolidated financial statements for the three and six months ended June 30, 2009.


	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Location	Net Loss			Net Gain		Net Loss
	(In Thousands)
Sales (decrease) increase	$	(682	)	$	2,516	$	—
Regulatory assets increase		1,257			—		8,277
Regulatory liabilities increase		1,530			—		30,382

In addition to commodity price risk, we are exposed to credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the creditworthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties intended to reduce our overall credit risk to an acceptable level and include the right to offset derivative assets and liabilities by counterparty.

We have derivative instruments with commodity exchanges and other counterparties which do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit rating agencies’ assessments of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to such provisions, could require us to post collateral on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of June 30, 2009, was $16.0 million, for which we had posted $1.0 million of collateral. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2009, we would have been required to provide to our counterparties $3.8 million of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

4. RATE MATTERS AND REGULATION

KCC Proceedings

Changes in Prices

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

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

On May 29, 2009, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2008. This change went into effect on June 1, 2009, and was designed to increase our annual retail revenues by $32.5 million.

We filed an abbreviated rate case application with the KCC on June 2, 2009, designed to increase our retail prices by $19.7 million per year. This increase represents costs associated with our remaining investments in natural gas and wind generation facilities that were not included in the price increase approved by the KCC in its January 21, 2009, order mentioned above. We expect the KCC to issue an order in this proceeding early next year.

5. DEBT FINANCING

On June 11, 2009, KGE issued $300.0 million principal amount of first mortgage bonds at a discount yielding 6.725%, bearing stated interest at 6.70% and maturing on June 15, 2019. Net proceeds of $297.5 million were used to repay borrowings under Westar Energy’s revolving credit facility, with those borrowed amounts principally related to investments in capital equipment.

6. TAXES

We recorded income tax expense of $15.7 million with an effective income tax rate of 29% for the three months ended June 30, 2009, and income tax expense of $2.7 million with an effective income tax rate of 31% for the same period of 2008; and income tax expense of $20.1 million with an effective income tax rate of 29% for the six months ended June 30, 2009, and an income tax net benefit of $15.6 million with an effective income tax rate of negative 30% for the same period of 2008. The decrease in the effective income tax rate for the three months ended June 30, 2009, is due to the utilization of production tax credits related to renewable energy. The increase in the effective income tax rate for the six months ended June 30, 2009, was due primarily to the recognition of previously unrecognized income tax benefits during the first quarter of 2008 as discussed below.

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

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

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

At December 31, 2008, our liability for unrecognized income tax benefits (including amounts claimed on amended returns filed in 2007) was $92.1 million. During the first quarter of 2009, unrecognized income tax benefits decreased from $92.1 million to $8.0 million. The net decrease in unrecognized income tax benefits was attributable primarily to the recognition of $31.8 million of unrecognized income tax benefits (net of credit carryforwards of $24.0 million utilized on settlement of the uncertain income tax positions) due to the completion of the IRS examination of years 2003 and 2004 and the resulting approval by the Joint Committee on Taxation of the U.S. Congress of our settlement with the IRS Office of Appeals regarding the re-characterization of the loss incurred on the sale of Protection One, Inc. At June 30, 2009, the liability related to unrecognized income tax benefits was $7.5 million. We do not believe that it is reasonably possible that there will be a significant change in the liability for unrecognized income tax benefits in the next 12 months. Included in this unrecognized income tax benefits balance was $1.5 million (net of tax) of tax positions, which if recognized, would favorably impact our effective income tax rate.

At June 30, 2009, and December 31, 2008, we had $1.5 million and $3.8 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. The decrease was attributable to the reduction in the liability for unrecognized income tax benefits. There were no penalties accrued at either June 30, 2009, or December 31, 2008.

As of June 30, 2009, and December 31, 2008, we maintained reserves of $3.8 million and $3.5 million, respectively, for probable assessments of taxes other than income taxes.

7. COMMITMENTS AND CONTINGENCIES

Environmental Projects

We will continue to make significant capital expenditures at our power plants to reduce emissions. The amount of these expenditures could materially increase or decrease depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation, the resolution of the Environmental Protection Agency (EPA) lawsuit described below and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment as a result of the EPA lawsuit or other requirements, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce the net production, reliability and availability of our power plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. In addition, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of these capital investments.

The environmental cost recovery rider allows for the more timely inclusion in retail prices of costs associated with capital expenditures tied directly to environmental improvements, including those required by the Federal Clean Air Act. We recover increased operating and maintenance costs through changes in our base rates following a rate review.

On February 28, 2008, we reached an agreement with the Kansas Department of Health and Environment (KDHE) to implement a plan to improve efficiency and to install new equipment to reduce regulated emissions from Jeffrey Energy Center. The projects are designed to meet requirements of the Clean Air Visibility Rule and reduce emissions over our entire generating fleet by eliminating more than 70% of sulfur dioxide and reducing nitrous oxides between 50% and 65%.

While an earlier issued EPA rule on mercury was vacated by a U.S. Court of Appeals ruling, we believe that mercury emissions will still be subject to strict future regulations and our costs to comply with these requirements could be material.

EPA Lawsuit

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

On January 22, 2004, the EPA notified us that certain projects completed at Jeffrey Energy Center violated certain requirements of the New Source Review program. On February 4, 2009, the Department of Justice (DOJ), on behalf of the EPA, filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. The court has entered a scheduling order that provides for a trial ready date of April 2011. A decision in favor of the DOJ and EPA, or a settlement prior to such a decision, if reached, could require us to update or install additional emissions controls at Jeffrey Energy Center. Additionally, we might be required to update or install emissions controls at our other coal-fired plants, pay fines or penalties or take other remedial action. Our ultimate costs to resolve this lawsuit could be material. We believe that costs related to updating or installing emissions controls would qualify for recovery in the prices we are allowed to charge our customers. However, if a penalty is assessed against us, the penalty could be material and possibly may not be recovered in prices. We expect to incur substantial legal fees and expenses related to the defense of this lawsuit. We are not able to estimate the possible loss or range of loss at this time.

FERC Investigation

We are responding to a non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008. On May 7, 2009, FERC staff advised us that it had preliminarily concluded that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleges we received $14.3 million of unjust profits through such activities. We believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We have sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. We are unable to predict the outcome of this investigation or its impact on our consolidated financial statements, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and potentially alter the manner in which we are permitted to buy and sell energy and use transmission service.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas and Missouri. We and the KDHE entered into a consent agreement in 1994 governing all future work at the Kansas sites. Under the terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, Inc., the current owner of some of the sites, ONEOK assumed total liability for remediation of seven sites, and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million. We have sole responsibility for remediation with respect to three sites.

Our liability for the former manufactured gas sites identified in Missouri is limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of our former Missouri assets.

8. LEGAL PROCEEDINGS

In late 2002, two of our executive officers resigned or were placed on administrative leave from their positions. Our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment. As of June 30, 2009, we had accrued liabilities of $75.4 million for compensation not yet paid to them and $6.7 million for legal fees and expenses they have incurred. As of December 31, 2008, we had accrued liabilities of $74.9 million for compensation not yet paid to them and $6.8 million for legal fees and expenses they have incurred. The arbitration has been stayed pending final resolution of criminal charges filed by the United States Attorney’s Office against them in U.S. District Court in the District of Kansas. We intend to vigorously defend against the counterclaims they filed in the arbitration. We are unable to predict the ultimate impact of this matter on our consolidated financial statements.

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

See also Note 7, “Commitments and Contingencies.”

9. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2009			2008			2009			2008
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	2,936		$	2,570		$	402		$	375
Interest cost		9,559			8,977			1,991			2,004
Expected return on plan assets		(9,280	)		(10,063	)		(1,197	)		(1,063	)
Amortization of unrecognized:
Transition obligation, net		—			—			983			983
Prior service costs		666			636			398			353
Actuarial loss, net		3,565			2,085			319			351

Net periodic cost	$	7,446		$	4,205		$	2,896		$	3,003


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2009			2008			2009			2008
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	5,872		$	5,140		$	804		$	750
Interest cost		19,118			17,954			3,982			4,008
Expected return on plan assets		(18,851	)		(20,125	)		(2,393	)		(2,126	)
Amortization of unrecognized:
Transition obligation, net		—			—			1,966			1,966
Prior service costs		1,332			1,272			795			706
Actuarial loss, net		7,130			4,170			638			702

Net periodic cost	$	14,601		$	8,411		$	5,792		$	6,006

As a result of recent guidance issued by the U.S. Department of the Treasury clarifying the assumptions underlying our pension plan, we expect to contribute approximately $34.0 million to our pension trust in 2009 compared to $51.9 million as previously reported in our 2008 Form 10-K. During the six months ended June 30, 2009, we contributed $18.2 million to our pension plan.

10. 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 benefit plans. The following table summarizes 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 June 30,	2009			2008			2009		2008
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	879		$	866		$	50	$	44
Interest cost		1,566			1,423			133		130
Expected return on plan assets		(1,183	)		(1,177	)		—		—
Amortization of unrecognized:
Transition obligation, net		14			14			14		14
Prior service costs		11			14			—		—
Actuarial loss, net		596			438			59		61

Net periodic cost	$	1,883		$	1,578		$	256	$	249


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2009			2008			2009		2008
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	1,757		$	1,710		$	101	$	101
Interest cost		3,132			2,840			265		259
Expected return on plan assets		(2,367	)		(2,353	)		—		—
Amortization of unrecognized:
Transition obligation, net		28			28			29		28
Prior service costs		22			28			—		—
Actuarial loss, net		1,193			848			118		116

Net periodic cost	$	3,765		$	3,101		$	513	$	504

As a result of recent guidance issued by the U.S. Department of the Treasury clarifying the assumptions underlying the Wolf Creek pension plan, we expect to fund approximately $7.0 million of the pension plan in 2009 compared to $11.8 million as previously reported in our 2008 Form 10-K. During the six months ended June 30, 2009, we funded $2.2 million of Wolf Creek’s pension plan.

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 and at wholesale in a multi-state region in the central United States under the regulation of the KCC and the FERC.

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2009 and our operating results for the three and six months ended June 30, 2009 and 2008. As you read Management’s Discussion and Analysis, please refer to our condensed consolidated financial statements and the accompanying notes, which contain our operating results.

SUMMARY OF SIGNIFICANT ITEMS

Increases in Net Income

Despite increases in most of our expenses, net income for the three and six months ended June 30, 2009, increased $32.5 million and $15.6 million, respectively, compared to the same periods last year due primarily to higher retail sales, lower fuel and purchased power expense, and for the six months ended June 30, 2009, a favorable tax settlement as described below. Primarily as a result of price increases authorized by the KCC, total retail sales increased $24.0 million and $46.5 million, respectively, for the three and six months ended June 30, 2009, compared to the same periods last year, although, retail megawatt hour (MWh) sales declined 1% and 4%, respectively for the same periods, due primarily to reduced industrial MWh sales. MWh sales for our industrial customers decreased 10% for the three months ended June 30, 2009, and 12% for the six months ended June 30, 2009, reflecting recessionary conditions, which are more acute for certain industries. Additionally, fuel and purchased power expense decreased $70.8 million and $76.7 million, respectively, over the same three and six month periods due principally to Wolf Creek not having had a scheduled maintenance outage during these periods, which significantly reduced our need to purchase power from other sources and decreased our average cost of fuel used for generation. Decreases in the average price of purchased power also contributed to the decrease in fuel and purchased power expense.

In January 2009, we reached a settlement with the IRS for years 2003 and 2004 associated with the re-characterization of a portion of the loss we incurred on the sale of Protection One from a capital loss to an ordinary loss. This settlement resulted in a first quarter 2009 net earnings benefit from discontinued operations of approximately $33.0 million, net of the amounts due to Protection One pursuant to the agreement related to the sale of Protection One. We did not record a similar benefit from discontinued operations for the six months ended June 30, 2008.

During the first quarter of 2008, we reached a settlement with the IRS for years 1995 through 2002 regarding issues principally related to the method used to capitalize overheads to electric plant. This settlement resulted in a first quarter 2008 net earnings benefit from continuing operations of approximately $39.4 million, including interest. This settlement also reduced our assessment of uncertain income tax liabilities; therefore, we reversed $17.8 million of accrued interest related to uncertain income tax liabilities in the first quarter of 2008. Ultimately, this settlement resulted in a substantial income tax benefit and significantly reduced interest expense for the six months ended June 30, 2008. We did not record a similar settlement in continuing operations during the same period this year, and, as a result, report much higher income tax and interest expense for the six months ended June 30, 2009.

Increases in Prices

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

Reduction in Planned Capital Expenditures

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

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with GAAP. Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted in our 2008 Form 10-K have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

From December 31, 2008 through June 30, 2009, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2008 Form 10-K.

OPERATING RESULTS

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

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

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

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

Energy marketing: Includes: (i) transactions based on market prices generally unrelated to the production of our generating assets; (ii) financially settled products and physical transactions sourced outside of our control area; (iii) fees we earn for marketing services that we provide for third parties; and (iv) changes in valuations of contracts related to such transactions that have yet to settle.

Transmission: Reflects transmission revenues, including those based on a tariff with the SPP.

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

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

Three and Six Months Ended June 30, 2009, Compared to Three and Six Months Ended June 30, 2008

Below we discuss our operating results for the three and six months ended June 30, 2009, compared to the results for the three and six months ended June 30, 2008. Changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.


	Three Months Ended June 30,											Six Months Ended June 30,
	2009			2008			Change			% Change		2009			2008			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)											(Dollars In Thousands, Except Per Share Amounts)
SALES:
Residential	$	148,304		$	123,350		$	24,954		20.2		$	268,958		$	231,575		$	37,383		16.1
Commercial		146,235			129,836			16,399		12.6			253,522			225,745			27,777		12.3
Industrial		77,681			76,303			1,378		1.8			141,486			140,382			1,104		0.8
Other retail		(17,179	)		1,579			(18,758	)	(b	)		(18,264	)		1,462			(19,726	)	(b	)

Total Retail Sales		355,041			331,068			23,973		7.2			645,702			599,164			46,538		7.8
Wholesale		65,651			87,746			(22,095	)	(25.2	)		151,396			190,925			(39,529	)	(20.7	)
Energy marketing		325			738			(413	)	(56.0	)		13,707			3,693			10,014		271.2
Transmission (a)		41,172			25,554			15,618		61.1			68,069			51,764			16,305		31.5
Other		5,623			6,113			(490	)	(8.0	)		10,705			12,500			(1,795	)	(14.4	)

Total Sales		467,812			451,219			16,593		3.7			889,579			858,046			31,533		3.7

OPERATING EXPENSES:
Fuel and purchased power		120,508			191,355			(70,847	)	(37.0	)		261,152			337,804			(76,652	)	(22.7	)
Operating and maintenance		139,810			130,966			8,844		6.8			261,978			246,984			14,994		6.1
Depreciation and amortization		63,814			49,605			14,209		28.6			122,028			98,501			23,527		23.9
Selling, general and administrative		53,638			44,254			9,384		21.2			101,619			85,910			15,709		18.3

Total Operating Expenses		377,770			416,180			(38,410	)	(9.2	)		746,777			769,199			(22,422	)	(2.9	)

INCOME FROM OPERATIONS		90,042			35,039			55,003		157.0			142,802			88,847			53,955		60.7

OTHER INCOME (EXPENSE):
Investment earnings		5,322			1,788			3,534		197.7			4,530			84			4,446		(b	)
Other income		1,153			4,343			(3,190	)	(73.5	)		4,410			10,160			(5,750	)	(56.6	)
Other expense		(2,341	)		(2,327	)		(14	)	(0.6	)		(6,903	)		(6,661	)		(242	)	(3.6	)

Total Other Income		4,134			3,804			330		8.7			2,037			3,583			(1,546	)	(43.1	)

Interest expense		40,094			30,311			9,783		32.3			75,170			41,001			34,169		83.3

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		54,082			8,532			45,550		533.9			69,669			51,429			18,240		35.5
Income tax expense (benefit)		15,696			2,687			13,009		484.1			20,098			(15,552	)		35,650		229.2

INCOME FROM CONTINUING OPERATIONS		38,386			5,845			32,541		556.7			49,571			66,981			(17,410	)	(26.0	)
Results of discontinued operations, net of tax		—			—			—		—			32,978			—			32,978		(b	)

NET INCOME		38,386			5,845			32,541		556.7			82,549			66,981			15,568		23.2
Preferred dividends		242			242			—		—			485			485			—		—

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	38,144		$	5,603		$	32,541		580.8		$	82,064		$	66,496		$	15,568		23.4

BASIC EARNINGS PER SHARE	$	0.35		$	0.06		$	0.29		483.3		$	0.75		$	0.67		$	0.08		11.9

(a)

Transmission: Reflects revenue derived from an SPP network transmission tariff. For the three months ended June 30, 2009, our SPP network transmission costs were $32.8 million. This amount, less $3.7 million retained by the SPP as administration cost, was returned to us as revenue. For the three months ended June 30, 2008, our SPP network transmission costs were $21.5 million with an administration cost of $2.7 million retained by the SPP. For the six months ended June 30, 2009, our SPP network transmission costs were $53.5 million. This amount, less $7.6 million retained by the SPP as administration cost, was returned to us as revenue. For the six months ended June 30, 2008, our SPP network transmission costs were $44.0 million with an administration cost of $5.8 million retained by the SPP.

(b)	Change greater than 1000%.


	Three Months Ended June 30,										Six Months Ended June 30,
	2009			2008		Change			% Change		2009			2008		Change			% Change
	(Sales in Thousands of Dollars, Volumes in Thousands of MWh)										(Sales in Thousands of Dollars, Volumes in Thousands of MWh)
Residential sales	$	148,304		$	123,350	$	24,954		20.2		$	268,958		$	231,575	$	37,383		16.1
Residential sales volumes		1,557			1,456		101		6.9			3,075			3,046		29		1.0

Commercial sales		146,235			129,836		16,399		12.6			253,522			225,745		27,777		12.3
Commercial sales volumes		1,903			1,888		15		0.8			3,515			3,553		(38	)	(1.1	)

Industrial sales		77,681			76,303		1,378		1.8			141,486			140,382		1,104		0.8
Industrial sales volumes		1,318			1,457		(139	)	(9.5	)		2,520			2,851		(331	)	(11.6	)

Other retail sales		(17,179	)		1,579		(18,758	)	(a	)		(18,264	)		1,462		(19,726	)	(a	)
Other retail sales volumes		22			22		—		—			43			45		(2	)	(4.4	)

Total retail sales		355,041			331,068		23,973		7.2			645,702			599,164		46,538		7.8
Total retail sales volumes		4,800			4,823		(23	)	(0.5	)		9,153			9,495		(342	)	(3.6	)

(a)	Change greater than 1000%.

Retail sales increased for the three and six months ended June 30, 2009, compared to the same periods last year due primarily to increases in our prices. Retail MWh sales, however, decreased this year compared to last year due primarily to decreases in industrial MWh sales. For the three and six months ended June 30, 2009, industrial MWh sales decreased 10% and 12%, respectively, due primarily to the effects of recessionary conditions, which served to reduce industrial demand for electricity. The 7% increase in residential MWh sales for the three months ended June 30, 2009, was due principally to warmer weather, particularly during the month of June. As measured by cooling degree days, the weather during the three months ended June 30, 2009, was 16% warmer than during the same period last year. The changes in other retail sales reflect our refund obligations related to the recovery of fuel and purchased power costs in excess of actual costs.


	Three Months Ended June 30,									Six Months Ended June 30,
	2009		2008		Change			% Change		2009		2008		Change			% Change
	(Sales in Thousands of Dollars, Volumes in Thousands of MWh)
Wholesale sales	$	65,651	$	87,746	$	(22,095	)	(25.2	)	$	151,396	$	190,925	$	(39,529	)	(20.7	)
Wholesale sales volumes		1,886		1,904		(18	)	(0.9	)		4,568		4,476		92		2.1

Wholesale sales decreased for the three and six months ended June 30, 2009, compared to the same periods last year due principally to lower average market prices of 28% and 21%, respectively.


	Three Months Ended June 30,									Six Months Ended June 30,
	2009		2008		Change			% Change		2009		2008		Change		% Change
	(Dollars In Thousands)
Energy marketing	$	325	$	738	$	(413	)	(56.0	)	$	13,707	$	3,693	$	10,014	271.2

Energy marketing increased for the six months ended June 30, 2009, compared to the same period in 2008 due primarily to our having settled forward contracts for the sale of electricity on favorable terms. See “—Other Information – Energy Marketing,” below for our expectations regarding future energy marketing margins.


	Three Months Ended June 30,									Six Months Ended June 30,
	2009		2008		Change			% Change		2009		2008		Change			% Change
	(Dollars In Thousands)
Fuel and purchased power	$	120,508	$	191,355	$	(70,847	)	(37.0	)	$	261,152	$	337,804	$	(76,652	)	(22.7	)

For the three and six months ended June 30, 2009, fuel and purchased power expense decreased due principally to our having purchased less power and lower unit costs for both fuel and purchased power. During these periods last year, scheduled maintenance outages at some of our plants resulted in us having purchased more power from other sources. We purchased 54% and 44% less power during the three and six months ended June 30, 2009, respectively, due primarily to Wolf Creek not having a scheduled maintenance outage during these periods this year. This, in addition to decreases in the cost of purchased power of 55% and 47%, resulted in decreases in purchased power expense of $51.8 million and $69.7 million for the respective three and six months ended June 30, 2009. Furthermore, the average cost of fuel used for generation decreased 23% and 13% for the three and six months ended June 30, 2009, respectively. This decrease is due primarily to the cost of natural gas significantly decreasing and Wolf Creek having produced more power this year. For the three and six months ended June 30, 2009, the cost of natural gas used in our power plants decreased 64% and 60%, respectively. With the exception of two customers, the cost of fuel and purchased power we incurred in excess of costs recovered in rates is deferred as a regulatory asset until subsequent recovery. Offsetting decreases in fuel and purchased power expense during the three and six months ended June 30, 2009, was the recovery of $3.9 million and $12.0 million, respectively, for fuel and purchased power expense previously deferred compared to deferring $2.6 million and $8.6 million during the same periods the prior year. This resulted in a $6.5 million and $20.6 million increase in fuel and purchased power expense for the respective three and six months ended June 30, 2009.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008		Change		% Change
	(Dollars In Thousands)
Operating and maintenance	$	139,810	$	130,966	$	8,844	6.8	$	261,978	$	246,984	$	14,994	6.1

Operating and maintenance expense increased for the three and six months ended June 30, 2009, compared to the same periods last year due primarily to increases in SPP network transmission costs of $11.3 million and $9.6 million, respectively. These increases were in large part offset by higher transmission revenues of $15.6 million and $16.3 million, respectively. Also contributing to the increases were increases in the amounts expensed for previously deferred storm costs of $1.6 million and $3.0 million, respectively, and increases of $1.7 million and $2.1 million, respectively, in expenses for new generating facilities completed in the past year. Additionally, La Cygne Generation Station had a scheduled maintenance outage during the first quarter of 2009, resulting in a $1.6 million increase in operating and maintenance expense for the six months ended June 30, 2009. Partially offsetting the increases for the three months ended June 30, 2009, was a $5.5 million decrease in other power plant maintenance costs.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008		Change		% Change
	(Dollars In Thousands)
Depreciation and amortization	$	63,814	$	49,605	$	14,209	28.6	$	122,028	$	98,501	$	23,527	23.9

We completed a number of large construction projects in the past year. Consequently, depreciation and amortization expense increased for the three and six months ended June 30, 2009, compared to the same periods last year primarily as a result of the addition of generating plant assets, emission control equipment, wind generation and transmission facilities.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008		Change		% Change
	(Dollars In Thousands)
Selling, general and administrative	$	53,638	$	44,254	$	9,384	21.2	$	101,619	$	85,910	$	15,709	18.3

The increases in selling, general and administrative expense for the three and six months ended June 30, 2009, compared to the same periods last year were due primarily to increases in pension and other employee benefit costs of $6.6 million and $11.7 million, respectively. The increases in pension costs were attributable primarily to lower than expected investment returns on pension assets during 2008.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008		Change		% Change
	(Dollars In Thousands)
Investment earnings	$	5,322	$	1,788	$	3,534	197.7	$	4,530	$	84	$	4,446	(a	)

(a)	Change greater than 1000%.

Investment earnings increased for the three and six months ended June 30, 2009, compared to the same periods last year due principally to our having recorded gains of $5.3 million and $2.9 million, respectively, on investments held in a trust to fund retirement benefits. We recorded gains on these investments of $1.9 million and less than $0.1 million, respectively, in the same periods of 2008.


	Three Months Ended June 30,									Six Months Ended June 30,
	2009		2008		Change			% Change		2009		2008		Change			% Change
	(Dollars In Thousands)
Other income	$	1,153	$	4,343	$	(3,190	)	(73.5	)	$	4,410	$	10,160	$	(5,750	)	(56.6	)

Other income decreased for the three and six months ended June 30, 2009, compared to the same periods last year due principally to our having recorded less equity AFUDC this year. For the three months ended June 30, 2009, we recorded $0.7 million of equity AFUDC compared to recording $3.8 million of equity AFUDC for the same period last year. For the six months ended June 30, 2009, we recorded $3.3 million of equity AFUDC compared to recording $9.2 million of equity AFUDC for the same period last year. The decreases in equity AFUDC are attributable to the completion of several large construction projects in the past year.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008		Change		% Change
	(Dollars In Thousands)
Interest expense	$	40,094	$	30,311	$	9,783	32.3	$	75,170	$	41,001	$	34,169	83.3

Interest expense increased for the three months ended June 30, 2009, compared to the same period last year due primarily to interest on additional debt issued in 2008 to fund capital investments. Partially offsetting this increase was a $2.0 million decrease in interest incurred on Westar Energy’s revolving credit facility due primarily to lower average borrowings under the facility coupled with lower short-term interest rates.

During the six months ended June 30, 2008, we reversed $17.8 million of accrued interest associated with uncertain income tax liabilities, which significantly reduced interest expense. We did not record such a reversal for the six months ended June 30, 2009, and as a result, our interest expense is much higher this year. Absent this reversal, interest expense increased $16.4 million compared to last year due principally to interest on additional debt issued in 2008 to fund capital investments. These increases were partially offset by a $4.4 million decrease in interest on Westar Energy’s revolving credit facility due primarily to lower average amounts borrowed under the facility coupled with lower short-term interest rates.


	Three Months Ended June 30,							Six Months Ended June 30,
	2009		2008		Change		% Change	2009		2008			Change		% Change
	(Dollars In Thousands)
Income tax expense (benefit)	$	15,696	$	2,687	$	13,009	484.1	$	20,098	$	(15,552	)	$	35,650	229.2

Income tax expense increased for the three months ended June 30, 2009, compared to the same period last year due primarily to increased income from continuing operations before income taxes.

During the six months ended June 30, 2008, we recognized $28.7 million of previously unrecognized income tax benefits associated with uncertain income tax liabilities. We did not recognize similar income tax benefits in continuing operations during the same period this year resulting in higher income tax expense in 2009.

FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of June 30, 2009, compared to December 31, 2008.

Conditions in capital markets for short-term borrowing have improved from earlier this year, as evidenced by historically low London Interbank Offer Rates. Therefore, we decided to decrease cash holdings to levels more consistent with our historical practice, resulting in an $18.0 million decrease in cash and cash equivalents.

The fair market value of net energy marketing contracts decreased $47.4 million to $3.0 million at June 30, 2009. This was due primarily to decreases in coal prices which resulted in unfavorable changes in the market value of a fuel supply contract that was outstanding the entire period.

Prepaid expenses decreased $21.7 million due primarily to a $21.1 million decrease in prepaid expenses associated with corporate-owned life insurance (COLI) policies.

Regulatory assets, net of regulatory liabilities, decreased $42.9 million to $786.3 million at June 30, 2009, from $829.2 million at December 31, 2008. Total regulatory assets decreased $46.3 million due primarily to an $18.0 million decrease in previously deferred fuel expense, the amortization of $13.6 million for deferred employee benefits principally resulting from the amortization of prior service costs in Westar Energy’s pension plan and the amortization of $10.7 million for ice storms which occurred in prior periods. Regulatory liabilities decreased $3.4 million due primarily to a $33.1 million decrease in the market value of a fuel supply contract resulting principally from decreases in coal prices. This decrease was largely offset by a $15.6 million increase in fuel expense to be refunded to customers and a $12.5 million increase in removal costs for amounts collected, but not yet spent to remove retired assets.

On June 11, 2009, KGE issued $300.0 million of first mortgage bonds resulting in a corresponding increase in long-term debt. We used the proceeds to reduce the outstanding balance under Westar Energy’s revolving credit facility resulting in $112.2 million less short-term debt. See Note 5 of the Notes to Condensed Consolidated Financial Statements, “Debt Financing,” for additional information.

Deferred income taxes increased $30.4 million due primarily to a $28.2 million increase in deferred income taxes related to the effect of accelerated depreciation as permitted in the American Recovery and Reinvestment Act of 2009.

Other long-term liabilities decreased $31.5 million due primarily to a decrease in our liability for uncertain income tax positions and related accrued interest upon settlement of an IRS examination. See Note 6 of the Notes to Condensed Consolidated Financial Statements, “Taxes,” for additional detail on our uncertain income taxes positions.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy’s revolving credit facility and our access to capital markets. In the latter part of 2008 and continuing into 2009, capital markets have experienced unprecedented volatility. As a result, capital, particularly equity, has been more costly to obtain. In light of this volatility and the unpredictability of how long these capital market conditions will persist, we have reduced or delayed construction spending and other capital outlays in order to manage liquidity. See “–Future Cash Requirements” below for additional information. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting sales described in “– Operating Results” above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets.

Capital Resources

As of July 30, 2009, Westar Energy had a $730.0 million revolving credit facility under which $80.2 million had been borrowed and an additional $18.7 million of letters of credit had been issued. In addition, we had $3.2 million in cash and cash equivalents as of the same date.

Debt Financing

Cash Flows from Operating Activities

Operating activities provided $216.0 million of cash in the six months ended June 30, 2009, compared to cash used in operating activities of $2.2 million during the same period of 2008. The increase in cash provided by operating activities was due principally to our having paid $204.7 million less for fuel and purchased power and $44.0 million less to repair damage to our electrical system following storms. Partially offsetting these increases was a $54.6 million decrease in customer receipts during 2009 due primarily to lower receipts from our wholesale customers which have more than offset higher cash receipts from our retail customers.

Cash Flows used in Investing Activities

Investing activities used $355.4 million of cash in the six months ended June 30, 2009, compared to $438.1 million during the same period of 2008. We spent $338.8 million in the six months ended June 30, 2009, and $419.9 million in the same period of 2008 on additions to property, plant and equipment. The decrease in 2009 was due primarily to our having spent less for environmental and generation projects.

Cash Flows from Financing Activities

Financing activities in the six months ended June 30, 2009, provided $121.4 million of cash compared to $443.5 million in the same period of 2008. In the six months ended June 30, 2009, proceeds from long-term debt provided $297.5 million and we used cash to repay $112.2 million of short-term debt and to pay $60.9 million in dividends. In the six months ended June 30, 2008, proceeds from long-term debt provided $152.0 million, proceeds from the issuance of common stock provided $291.8 million and borrowings from COLI provided $61.6 million. We used cash to pay $50.5 million in dividends during this period. The increase in cash paid for dividends was due primarily to the issuance of additional shares of common stock and an increase in our dividend rate. The overall decrease in cash provided from financing activities was due principally to our having completed environmental and generation projects in 2008 that required substantial amounts of capital.

Future Cash Requirements

Due to the continued volatility in the capital markets and higher capital costs generally, in particular the cost of equity, we have reduced our anticipated capital expenditures for 2010 and 2011 by $366.8 million and $134.1 million, respectively, from what we reported in our 2008 Form 10-K. Our current plans anticipate capital expenditures for 2009 through 2011 as shown in the following table. We expect to meet these cash needs with internally generated cash flow, borrowings under Westar Energy’s revolving credit facility and through the issuance of securities in the capital markets.


	2009		2010		2011
	(In Thousands)
Generation:
Replacements and other	$	113,700	$	82,600	$	86,900
Additional capacity		39,200		12,300		10,200
Wind generation		2,200		—		—
Environmental		83,900		127,900		357,700
Nuclear fuel		23,000		30,100		24,400
Transmission (a)		132,500		214,800		163,400
Distribution:
Replacements and other		47,800		53,700		52,600
New customers		51,300		53,900		56,300
Other		7,700		20,200		21,400

Total capital expenditures	$	501,300	$	595,500	$	772,900



(a) Includes $9,000 in 2010 and $26,100 in 2011 for expenditures related to Prairie Wind Transmission.

Debt Covenants

Some debt instruments contain restrictions that require us to maintain leverage ratios as defined in the credit agreements. We were in compliance with these covenants as of June 30, 2009.

Credit Ratings

Moody’s Investors Service (Moody’s), Standard & Poor’s Ratings Group (S&P) and Fitch Investors Service (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate each agency’s assessment of our ability to pay interest and principal when due on our securities.

In August 2009, Moody’s upgraded its credit rating for Westar Energy’s and KGE’s first mortgage bonds/senior secured debt securities. In April 2009, S&P changed its rating outlook for Westar Energy and KGE debt securities from stable to positive. As of August 3, 2009, our ratings with the agencies and the outlooks for these ratings are as shown in the table below.


	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Unsecured Debt	Rating Outlook
Moody’s	Baa1	Baa1	Baa3	Stable
S&P	BBB	BBB	BBB-	Positive
Fitch	BBB+	BBB+	BBB	Stable

In general, less favorable credit ratings make borrowing more difficult and costly. Under our revolving credit facility our cost of borrowing is determined in part by our credit ratings. However, our ability to borrow under the revolving credit facility is not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical financial ratios, such as total debt to total capitalization and funds from operations to total debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices.

Certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of June 30, 2009, was $16.0 million, for which we had posted $1.0 million of collateral. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2009, we would have been required to provide to our counterparties $3.8 million of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2008, through June 30, 2009, there have been no material changes in our off-balance sheet arrangements. For additional information, see our 2008 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Pension and Post-Retirement Benefit Obligations

As a result of recent guidance issued by the U.S. Department of the Treasury clarifying the assumptions underlying our and Wolf Creek’s pension and post-retirement benefit plans, we expect to contribute approximately $53.0 million to the plans in 2009 compared to $76.0 million as previously reported in our 2008 Form 10-K. For the six months ended June 30, 2009, we contributed $26.6 million to our pension and post-retirement benefit plans.

From December 31, 2008, through June 30, 2009, there have been no other material changes outside the ordinary course of business in our contractual obligations and commercial commitments. For additional information, see our 2008 Form 10-K.

OTHER INFORMATION

Environmental Legislation

Our activities are subject to extensive and changing environmental regulation. On May 22, 2009, the State of Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. According to the law, in years 2011 through 2015 net renewable generation capacity needs to be 10% of the average peak demand for the three prior years. Net renewable generation needs to increase for years 2016 through 2019 to 15% of the average peak demand for the three prior years and in 2020 net renewable generation needs to increase to 20% of the average peak demand for the three prior years. We estimate that we may need to add about 150 to 200 megawatts of additional renewable generating capacity to meet the 2011 deadline.

In addition to laws currently in effect, numerous laws and regulations have been proposed related to what are referred to as greenhouse gases, including carbon dioxide (CO₂). We emit large amounts of CO ₂and other gasses through the operation of our power plants. On June 26, 2009, the U.S. House of Representatives passed a proposal that, if passed by the Senate and signed into law by the President, would require reductions in greenhouse gas emissions and, even beyond that, would impose additional expense for virtually all such emissions, even those below the stated targeted emission levels. The proposal identifies seven gasses, including CO₂, as greenhouse gasses. In addition, the proposal mandates utilities to meet an increasing percentage of energy demand from a combination of energy efficiency and renewable energy.

The degree to which we may need to reduce emissions or produce renewable energy and the timing of when such equipment may be required is uncertain. Both the timing and the nature of required investments and actions depend on specific outcomes that result from interpretation of new and existing regulation and legislation. Although we would expect to recover in the prices we charge our customers the costs that we incur to comply with environmental regulations, we can provide no assurance that we will be able to fully and timely do so. Failure to recover these associated costs could have a material adverse effect on our consolidated financial statements.

Abbreviated Rate Case Application

We filed an abbreviated rate case application with the KCC on June 2, 2009, designed to increase our retail prices by $19.7 million per year. This increase represents costs associated with our remaining investments in natural gas and wind generation facilities that were not included in the price increase approved by the KCC in its January 21, 2009, order. We expect the KCC to issue an order in this proceeding early next year.

Energy Marketing

Conditions in the wholesale energy markets have made it more difficult for us to produce energy marketing results at levels to which we have been historically accustomed. We believe these conditions may persist. As a result, we anticipate lower energy marketing margins during the remainder of the year and perhaps even beyond this year. Wholesale power market conditions include: relatively low electricity prices, lower natural gas prices, softer demand in general and, due to an increase in the number of parties transacting through exchanges and power pools, fewer customers willing to enter into bilateral wholesale energy contracts.

Fair Value of Energy Marketing and Fuel Contracts

The table below shows the fair value of energy marketing contracts outstanding as of June 30, 2009.


	Fair Value of Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2008	$	50,364
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		(16,284	)
Changes in fair value of contracts outstanding at the beginning and end of the period		(34,323	)
Fair value of new contracts entered into during the period		3,201

Fair value of contracts outstanding as of June 30, 2009 (a)	$	2,958

(a)

Approximately $8.8 million and $5.9 million of the fair value of energy marketing contracts is recognized as a regulatory asset and regulatory liability, respectively.

The sources of the fair values of the financial instruments related to these contracts and the maturity periods for the contracts as of June 30, 2009, 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			Maturity Over 5 Years
	(In Thousands)
Prices actively quoted (futures)	$	(311	)	$	(311	)	$	—		$	—		$	—
Prices provided by other external sources (swaps and forwards)		4,114			(5,700	)		4,376			4,388			1,050
Prices based on option pricing models (options and other) (a)		(845	)		2,097			(1,191	)		(1,406	)		(345	)

Total fair value of contracts outstanding	$	2,958		$	(3,914	)	$	3,185		$	2,982		$	705

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

New Accounting Pronouncements

FASB Codification

In June 2009, FASB approved its Codification as the exclusive authoritative reference for U.S. GAAP to be applied by nongovernmental entities. Under the Codification, with the exception of a small change in revenue recognition guidance, existing U.S. GAAP did not change. In addition, SEC rules and interpretive releases are still considered authoritative GAAP for SEC registrants. The Codification, which changes the referencing of accounting standards, is effective for interim and annual reporting periods ending after September 15, 2009. We adopted the Codification effective July 1, 2009, without a material impact on our consolidated financial statements.

Variable Interest Entities

Subsequent Events

Recognition and Presentation of Other-Than-Temporary Impairments

Employers’ Disclosures about Postretirement Benefit Plan Assets

Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities

In June 2008, FASB issued guidance for determining whether instruments granted in share-based payment transactions are participating securities. The guidance provides that all outstanding unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are participating securities and shall be included in the computation of EPS pursuant to the two-class method. This guidance is effective for fiscal years beginning after December 15, 2008, with retrospective application to prior periods. We adopted this guidance effective January 1, 2009. See Note 2 of the Notes to Condensed Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for additional information.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, FASB issued guidance that requires expanded disclosure to help investors better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. The guidance amends and expands the disclosure requirements related to derivative instruments and hedging activities by requiring qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosure about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This guidance is effective for fiscal years beginning after November 15, 2008. We adopted this guidance effective January 1, 2009. See Note 3 of the Notes to Condensed Consolidated Financial Statements, “Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management,” for additional information.

Fair Value Measurements

In September 2006, FASB issued guidance that defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. This guidance is effective for fiscal years beginning after November 15, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. In February 2008, FASB issued additional guidance that delays the effective date of the aforementioned guidance for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The non-financial items subject to the deferral include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. We adopted the guidance for financial assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. We adopted the guidance for non-financial assets and liabilities recognized at fair value on a non-recurring basis effective January 1, 2009. The adoption of this guidance did not have a material impact on our consolidated financial statements. See Note 3 of the Notes to Condensed Consolidated Financial Statements, “Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management,” for additional information.

In April 2009, FASB issued guidance on two separate fair value issues. Both of the releases are effective for interim and annual reporting periods ending after June 15, 2009, and we adopted both of them effective April 1, 2009. One of the releases provides guidance for determining fair value when the volume and level of activity for an asset or liability have significantly decreased and for identifying transactions that are not orderly. We adopted this guidance without a material impact on our consolidated financial statements. The other release requires disclosures about the fair value of financial instruments in interim reporting periods as well as in annual financial statements. See Note 3 of the Notes to Condensed Consolidated Financial Statements, “Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management,” for additional information.

Prairie Wind Transmission, LLC

On June 1, 2009, Prairie Wind Transmission, LLC, a joint venture company of which we own 50%, entered into an agreement with ITC Great Plains, LLC, Sunflower Electric Power Corporation and Mid-Kansas Electric Company regarding the segments of a proposed 765 kilovolt (kV) transmission project each company will construct in Kansas. Under the agreement, Prairie Wind Transmission will construct a new substation near Wichita and one near Medicine Lodge as well as a transmission line connecting the two substations. Prairie Wind Transmission will also construct a 765 kV transmission line south to the Kansas-Oklahoma border from either the Medicine Lodge substation or one of the substations that will be built by ITC Great Plains, LLC. The KCC approved this agreement on July 24, 2009.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including changes in commodity prices, debt and equity instrument values and interest rates. Experience in the capital markets in the latter part of 2008 and thus far in 2009 has revealed more volatility in these markets than typically has been exhibited in the past. This results in greater market risk. For additional information, see our 2008 Form 10-K, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

ITEM 4.

CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting during the three months ended June 30, 2009, 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

Information on other legal proceedings is set forth in Notes 7 and 8 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies – EPA Lawsuit – FERC Investigation” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 1A.

RISK FACTORS

There were no material changes in our risk factors from December 31, 2008, through June 30, 2009. For additional information, see our 2008 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

We held our annual meeting of shareholders on May 21, 2009. At the meeting, the holders of 96,359,101 shares voted either in person or by proxy to elect three Class I directors. Mr. Charles Q. Chandler IV, Mr. R.A. Edwards III and Ms. Sandra A.J. Lawrence were elected Class I directors to serve a term of three years.


	Votes
	For	Withheld
Charles Q. Chandler IV	94,490,440	1,868,661
R.A. Edwards III	94,569,424	1,789,677
Sandra A.J. Lawrence	94,542,139	1,816,962

The shareholders present or represented at the meeting voted for the ratification and confirmation of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2009. The result of the vote taken was as follows:

The shareholders present or represented at the meeting voted for an amendment to our long term incentive and share award plan that extends the termination date of the plan from June 30, 2009 to June 30, 2019 and adds a limitation that the exercise price of certain share awards under the plan may not be reduced without shareholder approval. The result of the vote taken was as follows:


	Votes
	For	Against	Abstain	Broker Non-Votes
Amendment to Long Term Incentive and Share Award Plan	70,464,703	10,029,812	609,518	15,255,068

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS


4(a)		Purchase Agreement between Kansas Gas and Electric Company and BNY Mellon Capital Markets, LLC, Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC as representatives of the Initial Purchasers named therein, dated June 8, 2009 (filed as Exhibit 4.1 to the Form 8-K filed on June 9, 2009).

4(b)		Fifty-Fourth Supplemental Indenture dated as of June 11, 2009, by and among Kansas Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as Trustee.

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 June 30, 2009

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 June 30, 2009

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2009 (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:	August 6, 2009	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle,
			Executive Vice President and Chief Financial Officer