Edgar Filing: WESTAR ENERGY INC /KS

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

¨	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 x 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		110,794,598 shares
(Class)		(Outstanding at July 27, 2010)

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

	Consolidated Statements of Changes in Equity	10

	Notes to Condensed Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44

Item 4.	Controls and Procedures	44

PART II. Other Information

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 3.	Defaults Upon Senior Securities	45

Item 4.	Removed and Reserved	45

Item 5.	Other Information	45

Item 6.	Exhibits	45

Signature		46

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition
2009 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2009
AFUDC		Allowance for Funds Used During Construction
COLI		Corporate-owned life insurance
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
JEC		Jeffrey Energy Center
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
MMBtu		Millions of British Thermal Units
Moody’s		Moody’s Investors Service
MWh		Megawatt hours
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen Oxide
ONEOK		ONEOK, Inc.
OTC		Over-the-counter
RECA		Retail Energy Cost Adjustment
RSUs		Restricted share units
S&P		Standard & Poor’s Ratings Group
SCR		Selective catalytic reduction
SPP		Southwest Power Pool
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

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:

•

the risk of operating in a heavily regulated industry subject to frequent and uncertain political, legislative, judicial and regulatory developments at any level of government that can affect our revenues and costs,

•

weather conditions and their effect on sales of electricity as well as on prices of energy commodities,

•

equipment damage from storms and extreme weather,

•

economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy,

•

the impact of changes in market conditions on employee 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 (Wolf Creek) decommissioning obligation,

•

the ability of our counterparties to make payments as and when due and to perform as required,

•

the existence of or introduction of competition into markets in which we operate,

•

risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated,

•

cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business,

•

availability of generating capacity and the performance of our generating plants,

•

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,

•

wholesale electricity prices,

•

changes in accounting requirements and other accounting matters,

•

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,

•

reduced demand for coal-based energy because of climate impacts and development of alternate energy sources,

•

current and future litigation, regulatory investigations, proceedings or inquiries,

•

other circumstances affecting anticipated operations, electricity sales and costs, and

•

other factors discussed elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009 (2009 Form 10-K), including in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other reports we file from time to time with the Securities and Exchange Commission.

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 2009 Form 10-K. No one section of this report deals with all aspects of the subject matter and additional information on some matters that could impact our consolidated financial results may be included in our 2009 Form 10-K. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

PART I. FINANCIAL INFORMATION

ITEM 1.

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, except par values)

(Unaudited)


	June 30, 2010		December 31, 2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,323	$	3,860
Accounts receivable, net of allowance for doubtful accounts of $4,278 and $5,231, respectively		272,723		216,186
Inventories and supplies, net		203,476		193,831
Energy marketing contracts		30,104		33,159
Taxes receivable		—		45,200
Deferred tax assets		7,402		7,927
Prepaid expenses		12,761		11,830
Regulatory assets		74,023		97,220
Other		18,297		20,269

Total Current Assets		622,109		629,482

PROPERTY, PLANT AND EQUIPMENT, NET		5,780,104		5,771,740

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET (See Note 12)		350,797		—

OTHER ASSETS:
Regulatory assets		736,380		758,538
Nuclear decommissioning trust		108,857		112,268
Energy marketing contracts		11,330		10,653
Other		209,561		242,802

Total Other Assets		1,066,128		1,124,261

TOTAL ASSETS	$	7,819,138	$	7,525,483

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	741	$	1,345
Current maturities of long-term debt of variable interest entities (See Note 12)		29,059		—
Short-term debt		240,760		242,760
Accounts payable		171,996		112,211
Accrued taxes		53,207		46,931
Energy marketing contracts		25,519		39,161
Accrued interest		47,248		76,955
Regulatory liabilities		32,137		39,745
Other		110,658		123,370

Total Current Liabilities		711,325		682,478

LONG-TERM LIABILITIES:
Long-term debt, net		2,490,632		2,490,734
Long-term debt of variable interest entities, net (See Note 12)		297,924		—
Obligation under capital leases		8,775		109,300
Deferred income taxes		964,395		964,461
Unamortized investment tax credits		154,617		127,777
Regulatory liabilities		120,615		100,963
Deferred regulatory gain from sale-leaseback		100,289		108,532
Accrued employee benefits		419,944		433,561
Asset retirement obligations		122,970		119,519
Energy marketing contracts		308		210
Other		103,472		117,720

Total Long-Term Liabilities		4,783,941		4,572,777

COMMITMENTS AND CONTINGENCIES (See Notes 7 and 8)
TEMPORARY EQUITY		3,454		3,443

EQUITY:
Westar Energy 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 110,671,883 shares and 109,072,000 shares, respectively		553,359		545,360
Paid-in capital		1,367,851		1,339,790
Retained earnings		374,209		360,199

Total Westar Energy Shareholders’ Equity		2,316,855		2,266,785

Noncontrolling Interests		3,563		—

Total Equity		2,320,418		2,266,785

TOTAL LIABILITIES AND EQUITY	$	7,819,138	$	7,525,483

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,
	2010			2009
REVENUES	$	495,181		$	467,812

OPERATING EXPENSES:
Fuel and purchased power		137,116			120,508
Operating and maintenance		121,810			139,810
Depreciation and amortization		67,107			63,814
Selling, general and administrative		48,154			53,638

Total Operating Expenses		374,187			377,770

INCOME FROM OPERATIONS		120,994			90,042

OTHER INCOME (EXPENSE):
Investment (losses) earnings		(655	)		5,322
Other income		1,041			1,153
Other expense		(2,403	)		(2,341	)

Total Other (Expense) Income		(2,017	)		4,134

Interest expense		43,289			40,094

INCOME FROM OPERATIONS BEFORE INCOME TAXES		75,688			54,082
Income tax expense		21,158			15,696

NET INCOME		54,530			38,386
Less: Net income attributable to noncontrolling interests		1,219			—

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		53,311			38,386
Preferred dividends		242			242

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	53,069		$	38,144

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Earnings available from continuing operations	$	0.47		$	0.35
Discontinued operations, net of tax		—			—

Earnings per common share, basic and diluted	$	0.47		$	0.35

Average equivalent common shares outstanding		111,522,803			109,538,854
DIVIDENDS DECLARED PER COMMON SHARE	$	0.31		$	0.30
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	$	53,311		$	38,386

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,
	2010			2009
REVENUES	$	955,011		$	889,579

OPERATING EXPENSES:
Fuel and purchased power		270,916			261,152
Operating and maintenance		242,983			261,978
Depreciation and amortization		134,037			122,028
Selling, general and administrative		94,080			101,619

Total Operating Expenses		742,016			746,777

INCOME FROM OPERATIONS		212,995			142,802

OTHER INCOME (EXPENSE):
Investment earnings		1,102			4,530
Other income		1,895			4,410
Other expense		(6,897	)		(6,903	)

Total Other (Expense) Income		(3,900	)		2,037

Interest expense		87,905			75,170

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		121,190			69,669
Income tax expense		34,979			20,098

INCOME FROM CONTINUING OPERATIONS		86,211			49,571
Results of discontinued operations, net of tax		—			32,978

NET INCOME		86,211			82,549
Less: Net income attributable to noncontrolling interests		2,220			—

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		83,991			82,549
Preferred dividends		485			485

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	83,506		$	82,064

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Earnings available from continuing operations	$	0.75		$	0.45
Discontinued operations, net of tax		—			0.30

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

Average equivalent common shares outstanding		111,224,830			109,435,488
DIVIDENDS DECLARED PER COMMON SHARE	$	0.62		$	0.60
AMOUNTS ATTRIBUTABLE TO WESTAR ENERGY:
Income from continuing operations	$	83,991		$	49,571
Results of discontinued operations, net of tax		—			32,978

Net income	$	83,991		$	82,549

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,
	2010			2009
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	86,211		$	82,549
Discontinued operations, net of tax		—			(32,978	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		134,037			122,028
Amortization of nuclear fuel		12,832			8,602
Amortization of deferred regulatory gain from sale-leaseback		(2,748	)		(2,748	)
Amortization of prepaid corporate-owned life insurance		9,348			10,238
Non-cash compensation		5,262			2,720
Net changes in energy marketing assets and liabilities		(805	)		6,434
Accrued liability to certain former officers		802			312
Net deferred income taxes and credits		56,227			32,045
Stock based compensation excess tax benefits		(411	)		(269	)
Allowance for equity funds used during construction		(1,084	)		(3,277	)
Changes in working capital items, net of acquisitions and dispositions:
Accounts receivable		(56,536	)		(41,362	)
Inventories and supplies		(9,259	)		(2,607	)
Prepaid expenses and other		10,403			(341	)
Accounts payable		52,422			(21,330	)
Accrued taxes		51,692			10,207
Other current liabilities		(91,108	)		67,866
Changes in other assets		19,340			16,589
Changes in other liabilities		(37,807	)		(38,692	)

Cash Flows from Operating Activities		238,818			215,986

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(237,645	)		(338,768	)
Investment in corporate-owned life insurance		(18,884	)		(17,724	)
Purchase of securities within the nuclear decommissioning trust fund		(166,916	)		(22,538	)
Sale of securities within the nuclear decommissioning trust fund		167,209			21,145
Proceeds from investment in corporate-owned life insurance		875			1,216
Other investing activities		(395	)		1,300

Cash Flows used in Investing Activities		(255,756	)		(355,369	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		(2,000	)		(112,200	)
Proceeds from long-term debt		—			297,507
Retirements of long-term debt		(980	)		(802	)
Repayments of long-term debt of variable interest entities		(10,450	)		—
Repayment of capital leases		(1,174	)		(9,013	)
Borrowings against cash surrender value of corporate-owned life insurance		71,309			7,547
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(2,233	)		(3,151	)
Stock based compensation excess tax benefits		411			269
Issuance of common stock, net		27,288			2,181
Distributions to shareholders of noncontrolling interests		(2,094	)		—
Cash dividends paid		(63,676	)		(60,928	)

Cash Flows from Financing Activities		16,401			121,410

NET DECREASE IN CASH AND CASH EQUIVALENTS		(537	)		(17,973	)
CASH AND CASH EQUIVALENTS:
Beginning of period		3,860			22,914

End of period	$	3,323		$	4,941

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

WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)


	Westar Energy Shareholders
	Cumulative preferred stock		Common stock		Paid-in capital			Retained earnings			Noncontrolling interests			Total equity
Balance at December 31, 2008	$	21,436	$	541,556	$	1,326,391		$	318,197		$	—		$	2,207,580

Net income		—		—		—			82,549			—			82,549
Issuance of common stock, net		—		2,056		5,540			—			—			7,596
Preferred dividends, net of retirements		—		—		—			(485	)		—			(485	)
Dividends on common stock		—		—		—			(65,949	)		—			(65,949	)
Reclass to Temporary Equity		—		—		(12	)		—			—			(12	)
Amortization of restricted stock		—		—		2,230			—			—			2,230
Stock compensation and tax benefit		—		—		(1,847	)		—			—			(1,847	)

Balance at June 30, 2009	$	21,436	$	543,612	$	1,332,302		$	334,312		$	—		$	2,231,662

Balance at December 31, 2009	$	21,436	$	545,360	$	1,339,790		$	360,199		$	—		$	2,266,785

Consolidation of noncontrolling interests		—		—		—			—			3,435			3,435
Net income		—		—		—			83,991			2,220			86,211
Issuance of common stock, net		—		7,999		26,199			—			—			34,198
Preferred dividends, net of retirements		—		—		—			(485	)		—			(485	)
Dividends on common stock		—		—		—			(69,496	)		—			(69,496	)
Reclass to Temporary Equity		—		—		(11	)		—			—			(11	)
Amortization of restricted stock		—		—		4,719			—			—			4,719
Stock compensation and tax benefit		—		—		(2,846	)		—			—			(2,846	)
Distributions to shareholders of noncontrolling interests		—		—		—			—			(2,092	)		(2,092	)

Balance at June 30, 2010	$	21,436	$	553,359	$	1,367,851		$	374,209		$	3,563		$	2,320,418

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 687,000 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 Wolf Creek, a nuclear power plant located near Burlington, Kansas. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our unaudited condensed consolidated financial statements 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 generally accepted accounting principles (GAAP) have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs), reported as a single operating segment, for which we maintain controlling interest or are the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2009 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 condensed 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, 2010, 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 other income (for equity funds) and interest expense (for borrowed funds) for 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,
	2010		2009		2010		2009
	(In Thousands)
Borrowed funds	$	948	$	717	$	1,692	$	2,846
Equity funds		630		722		1,084		3,277

Total	$	1,578	$	1,439	$	2,776	$	6,123

Average AFUDC Rates		2.3%		3.2%		2.3%		4.7%

Earnings Per Share

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. Therefore, we apply the two-class method of computing basic and diluted earnings per share (EPS).

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 our forward sale agreement, RSUs that do not have nonforfeitable rights to dividend equivalents and stock options. We compute the dilutive effect of these shares 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,
	2010		2009		2010		2009
	(Dollars In Thousands, Except Per Share Amounts)
Income from continuing operations	$	54,530	$	38,386	$	86,211	$	49,571
Less: Income attributable to noncontrolling interest		1,219		—		2,220		—

Income from continuing operations attributable to Westar Energy		53,311		38,386		83,991		49,571
Less: Preferred dividends		242		242		485		485
Income from continuing operations allocated to RSUs		298		154		466		224

Income from continuing operations attributable to common stock	$	52,771	$	37,990	$	83,040	$	48,862

Weighted average equivalent common shares outstanding – basic		111,522,803		109,538,854		111,224,830		109,435,488
Effect of dilutive securities:
Restricted share units		118,083		—		73,190		—
Forward sale agreement		86,431		—		29,387		—
Employee stock options		—		339		107		368

Weighted average equivalent common shares outstanding – diluted (a)		111,727,317		109,539,193		111,327,514		109,435,856

Earnings from continuing operations per common share, basic and diluted	$	0.47	$	0.35	$	0.75	$	0.45

(a)	For the six months ended June 30, 2010, potentially dilutive shares not included in the denominator because they are antidilutive totaled 889 shares. For the three months ended June 30, 2010, and three and six months ended June 30, 2009, we did not have any antidilutive shares.

Supplemental Cash Flow Information


	Six Months Ended June 30,
	2010			2009
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	83,556		$	67,484
Income taxes, net of refunds		(44,272	)		(9,063	)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		23,763			41,927
Property, plant and equipment additions of variable interest entities (a)		356,964			—
Jeffrey Energy Center 8% leasehold interest (a)		(108,706	)		—
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans		8,361			5,409
Debt of variable interest entities (a)		337,951			—
Capital lease for Jeffrey Energy Center 8% leasehold interest (a)		(106,423	)		—
Assets acquired through capital leases		321			1,178


(a) These transactions result from the consolidation of the VIEs discussed in Note 12, “Variable Interest Entities.”

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.

Consolidation Guidance for Variable Interest Entities

In June 2009, the Financial Accounting Standards Board (FASB) issued guidance that amends the consolidation guidance for VIEs. The amended guidance requires a qualitative assessment rather than a quantitative assessment in determining the primary beneficiary of a VIE and significantly changes the criteria to consider in determining the primary beneficiary. Pursuant to the amended guidance, there is no exclusion, or “grandfathering,” of VIEs that were not consolidated under prior guidance. This amended guidance was effective for annual reporting periods beginning after November 15, 2009. We adopted the guidance effective January 1, 2010, and, as a result, began consolidating certain VIEs that hold assets we lease. See Note 12, “Variable Interest Entities,” 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.

During the second quarter of 2010, we changed our investment advisor for the nuclear decommissioning trust (NDT). The transition resulted in the sale of all of our level 1 and level 2 investments and the purchase of additional level 2 investments. Level 2 investments, whether in the NDT or our trading securities portfolio, are held in investment funds that do not have quoted market prices to measure fair value. Therefore, we measure fair value of level 2 investments at net asset value.

We still maintain certain level 3 investments in private equity, high-yield bonds and 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 measured by utilizing both market- and income-based models, public company comparables, at cost or at the value derived from subsequent financings. Certain adjustments are made 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. Fair value for these investments is determined by using subjective market- and income-based estimates such as projected cash flows and future interest rates. To measure the fair value of real estate securities we use a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

Energy marketing contracts can be exchange-traded or traded 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, nonperformance risk, 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, estimates by management 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, 2010, and December 31, 2009.


	As of June 30, 2010				As of December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,373,408	$	2,618,814	$	2,373,723	$	2,528,456
Fixed-rate debt of variable interest entities		326,983		357,650		—		—

Recurring Fair Value Measurements

GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. The three levels of the hierarchy and examples are as follows:

•

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges and exchange-traded futures contracts.

•

Level 2 – Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

•

Level 3 – Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of options, real estate investments and long-term fuel supply contracts.

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, 2010
Assets:
Energy Marketing Contracts	$	2,422	$	13,910	$	25,102	$	41,434
Nuclear Decommissioning Trust:
Domestic equity		—		47,216		2,547		49,763
International equity		—		15,554		—		15,554
Core bonds		—		30,208		—		30,208
High-yield bonds		—		4,434		6,122		10,556
Real estate securities		—		—		2,772		2,772
Cash equivalents		4		—		—		4

Total Nuclear Decommissioning Trust		4		97,412		11,441		108,857

Trading Securities:
Domestic equity		—		17,123		—		17,123
International equity		—		3,841		—		3,841
Core bonds		—		12,600		—		12,600

Total Trading Securities		—		33,564		—		33,564

Total Assets Measured at Fair Value	$	2,426	$	144,886	$	36,543	$	183,855

Liabilities:
Energy Marketing Contracts	$	2,433	$	14,225	$	9,169	$	25,827

As of December 31, 2009
Assets:
Energy Marketing Contracts	$	7,310	$	17,071	$	19,431	$	43,812
Nuclear Decommissioning Trust:
Domestic equity		34,961		5,317		2,262		42,540
International equity		1,208		24,736		—		25,944
Core bonds		16,082		5,524		—		21,606
High-yield bonds		5,579		—		5,741		11,320
Real estate securities		—		—		3,635		3,635
Commodities		5,563		—		—		5,563
Cash equivalents		1,660		—		—		1,660

Total Nuclear Decommissioning Trust		65,053		35,577		11,638		112,268

Trading Securities:
Domestic equity		—		18,344		—		18,344
International equity		—		4,422		—		4,422
Core bonds		—		11,853		—		11,853

Total Trading Securities		—		34,619		—		34,619

Total Assets Measured at Fair Value	$	72,363	$	87,267	$	31,069	$	190,699

Liabilities:
Energy Marketing Contracts	$	8,964	$	15,286	$	15,121	$	39,371

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of June 30, 2010, we had not recorded any right to reclaim cash collateral and had recorded $1.5 million for our obligation to return cash collateral. As of December 31, 2009, we had recorded $0.3 million for our right to reclaim cash collateral and $1.8 million for our obligation to return cash collateral.

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three and six months ended June 30, 2010.


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust							Net Balance
	Energy Marketing Contracts, net			Domestic Equity		High-yield Bonds		Real Estate Securities			Net Balance
	(In Thousands)
Balance as of March 31, 2010	$	14,452		$	2,384	$	5,979	$	2,779		$	25,594
Total realized and unrealized gains (losses) included in:
Earnings (a)		(1,777	)		—		—		—			(1,777	)
Regulatory assets		(1,324	)(b)		—		—		—			(1,324	)
Regulatory liabilities		2,097	(b)		47		143		(7	)		2,280
Purchases, issuances and settlements		2,485			116		—		—			2,601

Balance as of June 30, 2010	$	15,933		$	2,547	$	6,122	$	2,772		$	27,374


Balance as of December 31, 2009	$	4,310		$	2,262	$	5,741	$	3,635		$	15,948
Total realized and unrealized gains (losses) included in:
Earnings (a)		(1,773	)		—		—		—			(1,773	)
Regulatory assets		3,143	(b)		—		—		—			3,143
Regulatory liabilities		5,383	(b)		129		381		(863	)		5,030
Purchases, issuances and settlements		4,870			156		—		—			5,026

Balance as of June 30, 2010	$	15,933		$	2,547	$	6,122	$	2,772		$	27,374

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

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

The following table provides reconciliations 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 Core Bonds		Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds		Real Estate Securities			Trading Securities Core Bonds		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 revenues. Unrealized and realized gains and losses resulting from trading securities are included in investment earnings.

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

A portion of the gains and losses contributing to changes in net assets in the above table 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, 2010 and 2009, attributed to level 3 assets and liabilities as of June 30, 2010 and 2009, respectively.


	Three Months Ended June 30, 2010
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust							Net Balance
	Energy Marketing Contracts, net			Domestic Equity		High-yield Bonds		Real Estate Securities			Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	17		$	—	$	—	$	—		$	17
Regulatory assets		(1,958	)(b)		—		—		—			(1,958	)
Regulatory liabilities		1,975	(b)		53		143		(7	)		2,164

Total	$	34		$	53	$	143	$	(7	)	$	223


	Six Months Ended June 30, 2010
Total unrealized gains (losses) included in:
Earnings (a)	$	(180	)	$	—	$	—	$	—		$	(180	)
Regulatory assets		2,583	(b)		—		—		—			2,583
Regulatory liabilities		5,226	(b)		135		381		(863	)		4,879

Total	$	7,629		$	135	$	381	$	(863	)	$	7,282

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

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


	Three Months Ended June 30, 2009
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust								Trading Securities Core Bonds		Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds		Real Estate Securities			Trading Securities Core Bonds		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
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 revenues. Unrealized gains and losses resulting from trading securities are reported in investment earnings.

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

Certain investments in the NDT and all of our trading securities do not have a readily determinable fair value and are either investment companies or follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides further information on these investments.


	As of June 30, 2010				As of December 31, 2009				As of June 30, 2010
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	49,763	$	2,955	$	7,579	$	3,111	(a)	(a)
International equity		15,554		—		24,736		—	Upon Notice	1 day
Core bonds		30,208		—		5,524		—	Upon Notice	1 day
High-yield bonds		10,556		—		5,741		—	(b)	(b)
Real estate securities		2,772		—		3,635		—	(c)	(c)

Total Nuclear Decommissioning Trust	$	108,853	$	2,955	$	47,215	$	3,111

Trading Securities:
Domestic equity	$	17,123	$	—	$	18,344	$	—	Upon Notice	1 day
International equity		3,841		—		4,422		—	Upon Notice	1 day
Core bonds		12,600		—		11,853		—	Upon Notice	1 day

Total Trading Securities		33,564		—		34,619		—

Total	$	142,417	$	2,955	$	81,834	$	3,111

(a)

About 5% of the fair value is in long-term private equity funds that do not permit early withdrawal. The funds may begin liquidating in about 6 to 11 years unless the terms of the investments are extended. Our investments in these funds cannot be withdrawn until the underlying investments have been liquidated which may take years from the date of initial liquidation. The remaining 95% of the fair value permits liquidation upon notice and settles in one day.

(b)	About 58% of the fair value is in a commingled fund that permits redemptions on a quarterly basis with 30 days prior notice. The remaining 42% of the fair value is invested in a commingled fund that permits redemptions upon notice and settles within one day.

(c)	The nature of this investment requires relatively long holding periods which do not necessarily accommodate ready liquidity. In addition, recent adverse financial conditions affecting commercial real estate markets have further limited any liquidity associated with this investment.

Derivative Instruments

We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We trade electricity and other energy-related products using a variety of financial instruments, including futures contracts, options and swaps. We also trade energy commodity contracts.

We classify derivative instruments as energy marketing contracts on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities. With the exception of certain fuel supply and electricity contracts, which we record as regulatory assets or regulatory liabilities, we include the change in the fair value of energy marketing contracts in revenues on our consolidated statements of income. We do not hold derivative instruments that are designated as hedging instruments. The following table presents the fair value of derivative instruments reflected on our consolidated balance sheets.

Commodity Derivatives Not Designated as Hedging Instruments as of June 30, 2010


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	$	30,104	Energy marketing contracts	$	25,519
Other assets:			Long-term liabilities:
Energy marketing contracts		11,330	Energy marketing contracts		308

Total	$	41,434	Total	$	25,827

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 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	$	33,159	Energy marketing contracts	$	39,161
Other assets:			Long-term liabilities:
Energy marketing contracts		10,653	Energy marketing contracts		210

Total	$	43,812	Total	$	39,371

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, 2010 and 2009.


	Three Months Ended June 30, 2010					Six Months Ended June 30, 2010
Location	Net Gain Recognized		Net Loss Recognized			Net Gain Recognized			Net Loss Recognized
	(In thousands)
Revenues decrease	$	—	$	(946	)	$	—		$	(1,810	)
Regulatory assets increase (decrease)		—		39			(7,155	)		—
Regulatory liabilities increase		1,548		—			4,927			—

	Three Months Ended June 30, 2009					Six Months Ended June 30, 2009
Revenues (decrease) increase	$	—	$	(682	)	$	2,516		$	—
Regulatory assets increase		—		1,257			—			8,277
Regulatory liabilities increase		—		1,530			—			30,382

As of June 30, 2010, and December 31, 2009, we had under contract the following energy-related products.


		Net Quantity as of
	Unit of Measure	June 30, 2010	December 31, 2009
Electricity	MWh	3,451,261	4,147,800
Natural Gas	MMBtu	2,036,000	648,000
Coal	Ton	2,000,000	3,500,000

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 results.

Energy Marketing Activities

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 into certain positions attempting to take advantage of market trends and conditions. 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.

Price Risk

We use various types of fuel, including coal, natural gas, uranium, diesel and oil, to operate our plants and purchase power to meet customer demand. 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 results including cash flows. 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 for non-trading purposes.

Factors that affect our commodity price exposure are the quantity and availability of fuel used for generation, the availability of our power plants 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. Our commodity exposure is also affected by our nuclear plant refueling schedule. Our customers’ electricity usage also varies based on weather, the economy and other factors.

The wholesale power and fuel markets are volatile. This volatility impacts our costs of purchased power, fuel costs for our power plants and our participation in energy markets. We trade various types of fuel primarily to reduce exposure related to the volatility of commodity prices. A significant portion of our coal requirements is purchased under long-term contracts to hedge much of the fuel exposure for customers. 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.

Credit Risk

In addition to commodity price risk, we are exposed to credit risks associated with the financial condition of counterparties, product location (basis) pricing differentials, physical liquidity constraint 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 exposure to a level we deem acceptable and include the right to offset derivative assets and liabilities by counterparty.

We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, 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, 2010, and December 31, 2009, was $5.1 million and $1.4 million, respectively, for which we had posted collateral of $1.0 million as of June 30, 2010, and no collateral as of December 31, 2009. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2010, or December 31, 2009, we would have been required to provide to our counterparties $0.1 million of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

4. FINANCIAL INVESTMENTS

We report some of our investments in debt and equity securities at fair value and use the specific identification method to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We have debt and equity investments in a trust used to fund retirement benefits that we classify as trading securities. We include any unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. During the three and six months ended June 30, 2010, we recorded unrealized losses on these securities of $2.6 million and $1.1 million, respectively. We recorded unrealized gains of $8.7 million and $6.3 million during the three and six months ended June 30, 2009, respectively.

Available-for-Sale Securities

We hold investments in debt and equity securities in a trust fund for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of June 30, 2010, and December 31, 2009. At June 30, 2010, investments in the NDT fund were allocated 46% to domestic equity, 14% to international equity, 28% to core bonds, 10% to high-yield bonds, 2% to real estate securities and less than one percent to cash and cash equivalents. The core bond fund is limited to ensure that at least 80% of funds are invested in investment grade U.S. corporate and government fixed income securities, including mortgage-backed securities. As of June 30, 2010, the fair value of the debt securities in the NDT fund was $40.8 million, entirely held in closed end funds and bond mutual funds.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $12.6 million and $13.5 million, respectively, during the three and six months ended June 30, 2010. During the three and six months ended June 30, 2009, we realized losses of $6.9 million and $8.7 million, respectively, on these securities. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the costs and fair values of investments in the NDT fund as of June 30, 2010, and December 31, 2009.


			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value
	(In Thousands)
As of June 30, 2010:
Domestic equity	$	56,029	$	27	$	(6,293	)	$	49,763
International equity		17,561		—		(2,007	)		15,554
Core bonds		29,393		815		—			30,208
High-yield bonds		10,090		466		—			10,556
Real estate securities		6,207		—		(3,435	)		2,772
Cash equivalents		4		—		—			4

Total	$	119,284	$	1,308	$	(11,735	)	$	108,857

As of December 31, 2009:
Domestic equity	$	37,648	$	7,180	$	(2,288	)	$	42,540
International equity		22,014		4,835		(905	)		25,944
Core bonds		20,260		1,346		—			21,606
High-yield bonds		11,749		31		(460	)		11,320
Real estate securities		6,206		—		(2,571	)		3,635
Commodities		5,895		—		(332	)		5,563
Cash equivalents		1,660		—		—			1,660

Total	$	105,432	$	13,392	$	(6,556	)	$	112,268

The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2010, and December 31, 2009.


	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of June 30, 2010:
Domestic equity	$	47,217	$	(6,274	)	$	445	$	(19	)	$	47,662	$	(6,293	)
International equity		15,554		(2,007	)		—		—			15,554		(2,007	)
Real estate		30		(26	)		2,742		(3,409	)		2,772		(3,435	)

Total	$	62,801	$	(8,307	)	$	3,187	$	(3,428	)	$	65,988	$	(11,735	)

As of December 31, 2009:
Domestic equity	$	4,123	$	(361	)	$	10,061	$	(1,927	)	$	14,184	$	(2,288	)
International equity		198		(20	)		6,253		(885	)		6,451		(905	)
High-yield bonds		—		—			5,579		(460	)		5,579		(460	)
Real estate		40		(16	)		3,595		(2,555	)		3,635		(2,571	)
Commodities		—		—			5,563		(332	)		5,563		(332	)

Total	$	4,361	$	(397	)	$	31,051	$	(6,159	)	$	35,412	$	(6,556	)

5. RATE MATTERS AND REGULATION

KCC Proceedings

On June 11, 2010, the Kansas Corporation Commission (KCC) issued a final order approving an adjustment to our prices that we made earlier this year. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million.

On May 25, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2009. The new prices were effective June 1, 2010, and are expected to increase our annual retail revenues by $13.8 million.

On January 27, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in natural gas and wind generation facilities. The new prices were effective February 2010 and are expected to increase our annual retail revenues by $17.1 million.

FERC Proceedings

Our updated transmission formula rate, which includes projected 2010 transmission capital expenditures and operating costs, became effective January 1, 2010, and is expected to increase our annual transmission revenues by $16.8 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

On January 12, 2010, the Federal Energy Regulatory Commission (FERC) issued an order accepting our request to implement a cost-based formula rate for electricity sales to wholesale customers. The use of a cost-based formula rate allows us to annually adjust our prices to reflect changes in our cost of service. The cost-based formula rate was effective December 1, 2009.

6. TAXES

We recorded income tax expense of $21.2 million with an effective tax rate of 28% for the three months ended June 30, 2010, and income tax expense of $15.7 million with an effective income tax rate of 29% for the same period of 2009; and income tax expense of $35.0 million with an effective income tax rate of 29% for the six months ended June 30, 2010, and income tax expense of $20.1 million with an effective income tax rate of 29% for the same period of 2009. The decrease in the effective income tax rate for the three months ended June 30, 2010, was due primarily to the recognition of previously unrecognized income tax benefits as discussed below.

In January 2009, we reached a settlement with the Internal Revenue Service (IRS) for tax years 2003 and 2004 that included a determination of the amount of the net capital loss and net operating loss carryforwards available from the sale of a former subsidiary in 2004. This settlement resulted in a 2009 non-cash net earnings benefit from discontinued operations of approximately $33.7 million, net of $22.8 million paid to the former subsidiary under the sale agreement. We recorded $33.0 million of this benefit in the six months ended June 30, 2009.

During 2009, we also reached a tentative settlement with the IRS for the 2007 tax year that included an examination of the amended federal income tax returns filed for tax years 1999, 2005 and 2006. We filed these amended returns to recover a portion of the tax benefits from the net capital loss and net operating loss carryforwards described above. This settlement, which was approved by the Joint Committee on Taxation of the U.S. Congress and accepted by the IRS in April 2010, resulted in a cash tax refund of $34.9 million in the second quarter of 2010, which did not impact our consolidated statements of income.

In March 2010, the IRS commenced its examination of the 2008 tax year. We expect this examination to be completed within the next 12 months.

At June 30, 2010, and December 31, 2009, our liability for unrecognized income tax benefits was $2.8 million and $8.4 million, respectively. The net decrease in the liability for unrecognized income tax benefits was attributable primarily to the recognition of $5.8 million of unrecognized income tax benefits due to the completion of the IRS examination of tax years 1999, 2005, 2006 and 2007. We do not expect any other significant changes in the liability for unrecognized income tax benefits in the next 12 months.

As of June 30, 2010, and December 31, 2009, we had $0.6 million and $1.4 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. We had no tax related penalties accrued at either June 30, 2010, or December 31, 2009.

As of June 30, 2010, and December 31, 2009, we recorded $3.6 million 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 regulated 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 and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce net productivity of plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments.

The environmental cost recovery rider allows for the more timely inclusion in our prices the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our retail prices to recognize increased operating and maintenance costs, however, we must still file a general rate case with the KCC.

We have an agreement with the Kansas Department of Health and Environment (KDHE) to install new equipment to reduce regulated emissions from our generating fleet. The projects are designed to meet requirements of the Clean Air Visibility Rule and significantly reduce plant emissions.

While an earlier issued Environmental Protection Agency (EPA) rule on mercury was vacated by a U.S. Court of Appeals ruling, the Obama administration has indicated that it intends to enact stricter, technology-based regulations on mercury emissions. Our costs to comply with mercury emission requirements could be material.

EPA Lawsuit

Under Section 114(a) of the Federal Clean Air Act, the EPA has been 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 (JEC) violated certain requirements of the New Source Review program. On February 4, 2009, the Department of Justice, 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. On January 25, 2010, we announced a settlement of the lawsuit. The settlement was filed with the court, seeking its approval, and on March 26, 2010, the court entered an order approving the settlement without changes. The settlement provides for us to install a selective catalytic reduction (SCR) system on one of the three JEC coal units by the end of 2014. We have not yet engineered this project; however, our preliminary estimate of the cost of this SCR is approximately $200.0 million. This amount could materially increase or decrease depending on final engineering and design. Depending on the nitrogen oxide (NOx) emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, a second SCR system would be installed on another JEC coal unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge our customers. We will also invest $5.0 million over six years in environmental mitigation projects that we will own and $1.0 million in environmental mitigation projects that will be owned by a qualifying third party. We have also paid a $3.0 million civil penalty.

FERC Investigation

We continue to respond to a non-public investigation by 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 alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. On March 4, 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and potentially could 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 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. (ONEOK), 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 environmental liability for remediation of sites associated with assets we divested many years ago had been limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of those assets. In June 2010, the purchaser agreed to reduce our maximum liability to $2.5 million, which reflects our share of the purchaser’s expected remediation costs. We have paid $1.5 million of such costs.

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, 2010, we had accrued liabilities of $78.8 million for compensation not yet paid to them and $7.0 million for legal fees and expenses they have incurred. As of December 31, 2009, we had accrued liabilities of $77.6 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 5, “Rate Matters and Regulation,” and Note 7, “Commitments and Contingencies.”

9. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

Pursuant to a September 2009 KCC order, we recognize as a regulatory asset or liability the cumulative difference between pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. At the time of a future rate case, we expect to amortize such regulatory asset or liability as part of resetting our base prices.

The following table summarizes the net periodic costs for our pension and post-retirement benefit plans prior to the effects of capitalization.


	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2010			2009			2010			2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	3,445		$	2,936		$	330		$	402
Interest cost		9,854			9,559			1,754			1,991
Expected return on plan assets		(9,595	)		(9,280	)		(1,239	)		(1,197	)
Amortization of unrecognized:
Transition obligation, net		—			—			978			983
Prior service costs		697			666			533			398
Actuarial loss, net		4,347			3,565			59			319

Net periodic cost before regulatory adjustment		8,748			7,446			2,415			2,896
Regulatory adjustment		(3,117	)		—			457			—

Net periodic cost	$	5,631		$	7,446		$	2,872		$	2,896


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2010			2009			2010			2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	6,963		$	5,872		$	763		$	804
Interest cost		19,696			19,118			3,542			3,982
Expected return on plan assets		(19,192	)		(18,851	)		(2,599	)		(2,393	)
Amortization of unrecognized:
Transition obligation, net		—			—			1,956			1,966
Prior service costs		1,364			1,332			1,077			795
Actuarial loss, net		8,592			7,130			160			638

Net periodic cost before regulatory adjustment		17,423			14,601			4,899			5,792
Regulatory adjustment		(6,238	)		—			887			—

Net periodic cost	$	11,185		$	14,601		$	5,786		$	5,792

During the six months ended June 30, 2010 and 2009, we contributed $16.8 million and $18.2 million, respectively, to the Westar Energy pension trust.

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 plans. The following table summarizes the net periodic costs for KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization.


	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2010			2009			2010		2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	1,048		$	879		$	36	$	50
Interest cost		1,747			1,566			130		133
Expected return on plan assets		(1,347	)		(1,183	)		—		—
Amortization of unrecognized:
Transition obligation, net		14			14			14		14
Prior service costs		7			11			—		—
Actuarial loss, net		712			596			69		59

Net periodic cost before regulatory adjustment		2,181			1,883			249		256
Regulatory adjustment		(466	)		—			—		—

Net periodic cost	$	1,715		$	1,883		$	249	$	256


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2010			2009			2010		2009
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	2,072		$	1,757		$	90	$	101
Interest cost		3,471			3,132			260		265
Expected return on plan assets		(2,727	)		(2,367	)		—		—
Amortization of unrecognized:
Transition obligation, net		28			28			28		29
Prior service costs		14			22			—		—
Actuarial loss, net		1,318			1,193			138		118

Net periodic cost before regulatory adjustment		4,176			3,765			516		513
Regulatory adjustment		(788	)		—			—		—

Net periodic cost	$	3,388		$	3,765		$	516	$	513

During the six months ended June 30, 2010 and 2009, we funded $1.8 million and $2.2 million, respectively, of Wolf Creek’s pension plan contribution.

11. COMMON STOCK ISSUANCE

During the six months ended June 30, 2010, Westar Energy sold 1.2 million shares of common stock for $25.0 million through a 2007 Sales Agency Financing Agreement with a broker dealer subsidiary of a bank. Westar Energy used the proceeds from the issuance of common stock to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes.

On April 2, 2010, Westar Energy entered into a new, three-year Sales Agency Financing Agreement and forward sale agreement with the same bank and its broker dealer subsidiary. The maximum amount that Westar Energy may offer and sell under the agreements is the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the Sales Agency Financing Agreement, Westar Energy may offer and sell shares of its common stock from time to time through the broker dealer subsidiary, as agent. Westar Energy will pay the broker dealer a commission equal to 1% of the sales price of all shares sold under the agreement.

In addition, under the terms of the Sales Agency Financing Agreement and forward sale agreement, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, with the bank borrowing shares of Westar Energy’s common stock from third parties and selling them through the broker dealer. The use of a forward sale agreement allows Westar Energy the means to minimize equity market uncertainty by pricing a common stock offering under then existing market conditions while mitigating share dilution by postponing the issuance of common stock until funds are needed. Westar Energy is also able to better match the timing of its financing needs with its capital investment and regulatory plans. The forward sale transactions are entered into at market prices; therefore, the forward sale agreement has no initial fair value. Westar Energy will not receive any proceeds from the sale of common stock under the forward sale agreement until the transactions are settled, which must occur within a year of the date each transaction is entered. Upon settlement, Westar Energy will record the forward sale agreement within equity. Except in specified circumstances or events that would require physical share settlement, Westar Energy is able to elect to settle any forward sale transactions by means of a physical share, cash or net share settlement, and is also able to elect to settle the forward sale transactions in whole, or in part, earlier than the stated maturity dates. Currently, Westar Energy anticipates settling the forward sale transactions through physical share settlement and expects to use the proceeds to repay borrowings under its revolving credit facility, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes. While the shares are initially priced by the bank at a fixed price, because of the fixed contractual terms, Westar Energy’s net proceeds from the forward sale transactions, assuming physical share settlement, will vary depending on the time of settlement.

During the three months ended June 30, 2010, Westar Energy entered into forward sale transactions with respect to an aggregate of approximately 3.7 million shares of common stock. Assuming physical share settlement of the aforementioned forward sale transactions at June 30, 2010, Westar Energy would have received aggregate proceeds of approximately $83.0 million based on an average forward price of $22.23 per share.

12. VARIABLE INTEREST ENTITIES

Effective January 1, 2010, we adopted accounting guidance that amends the consolidation criteria for VIEs. The amended guidance requires a qualitative assessment rather than a quantitative assessment in determining the primary beneficiary of a VIE. A qualitative assessment includes understanding the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. We have concluded that trusts holding assets we lease, which include the 8% interest in JEC, the 50% interest in La Cygne Generating Station (La Cygne) unit 2 and railcars we use to transport coal to some of our plants, are VIEs of which we are the primary beneficiary. With the consolidation of these VIEs, we ceased accounting for these transactions as leases. See Note 13, “Leases,” for additional information.

We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of such entities. We also continuously assess whether we are the primary beneficiary of the VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.

8% Interest in Jeffrey Energy Center

Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

Railcars

Under two separate agreements that expire in May 2013 and November 2014, we lease railcars from trusts to transport coal to some of our power plants. The trusts were financed with equity contributions from owner participants and debt issued by the trusts. The trusts were created specifically to purchase the railcars and lease them to us, and do not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trusts. In determining the primary beneficiary of the trusts, we concluded that the activities of the trusts that most significantly impact their economic performance and that we have the power to direct include the operation, maintenance and repair of the railcars and our ability to exercise a purchase option at the end of the agreements at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trusts that could potentially be significant if the fair value of the railcars at the end of the agreements is greater than the fixed amounts. Our agreements with these trusts also include renewal options during which time we would pay a fixed amount of rent. We have the potential to receive benefits from the trusts during the renewal periods if the fixed amount of rent is less than the amount we would be required to pay under a new agreement.

Financial Statement Impact

As of June 30, 2010, we have recorded the following assets and liabilities on our consolidated balance sheet as a result of consolidating the VIEs described above.


As of June 30, 2010	Dollar Amount
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	350,797
Regulatory asset (a)		3,514

Liabilities:
Current maturities of long-term debt of variable interest entities	$	29,059
Accrued interest (b)		5,313
Long-term debt of variable interest entities, net		297,924

(a) Included in other regulatory assets on our consolidated balance sheet.
(b) Included in accrued interest on our consolidated balance sheet.

All of the liabilities noted in the table above relate to the purchase of the reported property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.

Additionally, the consolidation of these VIEs affected the presentation of our consolidated statements of cash flows. A portion of lease expenditures previously presented as operating cash flows is now allocated between operating and financing cash flows. Total cash flows did not change.

13. LEASES

As discussed in Note 12, “Variable Interest Entities,” the adoption of new accounting guidance effective January 1, 2010, eliminated the lease accounting we previously reported for our 8% interest in JEC, our 50% interest in La Cygne unit 2 and railcars we use to transport coal to some of our plants. As a result, the future commitments under operating leases, minimum annual rental payments under capital leases and recorded capital lease assets have decreased significantly compared to those reported in our 2009 Form 10-K. However, we remain contractually obligated to meet our future commitments and to make annual payments in accordance with the lease agreements that relate to these assets.

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. These leases have various terms and expiration dates ranging from one to 20 years.

In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term. Our estimated future commitments under operating leases are as follows.


Total Operating Leases	June 30, 2010		December 31, 2009
	(In Thousands)
2010	$	8,202	$	49,181
2011		12,591		48,450
2012		13,818		50,453
2013		11,557		46,698
2014		9,628		43,195
Thereafter		27,686		249,592

Total future commitments	$	83,482	$	487,569

Capital Leases

We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements. The lease term for vehicles is from two to 14 years depending on the type of vehicle. Computer equipment has a lease term of two to four years.

Assets recorded under capital leases are listed below.


	June 30, 2010			December 31, 2009
	June 30, 2010			December 31, 2009
	(In Thousands)
Vehicles	$	17,486		$	18,991
Computer equipment and software		4,961			4,640
Jeffrey Energy Center 8% interest		—			118,623
Accumulated amortization		(11,702	)		(21,736	)

Total capital leases	$	10,745		$	120,518

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


Total Capital Leases	June 30, 2010			December 31, 2009
Total Capital Leases	June 30, 2010			December 31, 2009
	(In Thousands)
2010	$	2,669		$	17,685
2011		1,746			14,776
2012		1,659			11,540
2013		1,451			7,256
2014		1,348			7,037
Thereafter		2,022			111,547

		10,895			169,841
Amounts representing imputed interest		(150	)		(51,606	)

Present value of net minimum lease payments under capital leases		10,745			118,235
Less current portion		1,970			8,935

Total long-term obligation under capital leases	$	8,775		$	109,300

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Certain matters discussed in Management’s Discussion and Analysis 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.

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 FERC.

In Management’s Discussion and Analysis, we discuss our general financial condition, significant changes that occurred during 2010 and our operating results for the three and six months ended June 30, 2010 and 2009. 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

Earnings Per Share

We reported basic EPS of $0.47 for the three months ended June 30, 2010, compared to basic EPS of $0.35 for the same period last year. For each of the six month periods ended June 30, 2010 and 2009, we reported basic EPS of $0.75. Basic EPS for the six months ended June 30, 2009, however, included $0.30 of earnings attributable to discontinued operations.

Increase in Income from Continuing Operations

Income from continuing operations for the three and six months ended June 30, 2010, increased $16.1 million and $36.6 million, respectively, compared to the same periods last year due principally to higher retail revenues and lower operating and maintenance expense. Retail revenues increased due primarily to increased sales of electricity to industrial customers. Operating and maintenance expense was lower due primarily to the consolidation of VIEs and a reduction in our maximum liability for environmental remediation costs related to former manufactured gas sites in Missouri. Lower investment earnings and higher income tax expense partially offset these factors for the three months ended June 30, 2010, while higher income tax, interest and depreciation and amortization expenses served to offset partially the aforementioned factors for the six months ended June 30, 2010.

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 the instructions to Form 10-Q and Article 10 of Regulation S-X. 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 2009 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, 2009, through June 30, 2010, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2009 Form 10-K.

OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

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

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

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

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. This category also includes energy marketing transactions unrelated to the production of our generating assets, changes in valuations of related contracts and fees we earn for marketing services that we provide for third parties.

Electric utility revenues are impacted by things such as rate regulation, fuel costs, customer conservation efforts, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use, as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among our residential customers. Mild weather reduces customer demand. Our wholesale revenues 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, 2010, Compared to Three and Six Months Ended June 30, 2009

Below we discuss our operating results for the three and six months ended June 30, 2010, compared to the results for the three and six months ended June 30, 2009. Significant 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,
	2010			2009			Change			% Change		2010			2009			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)											(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	150,094		$	148,304		$	1,790		1.2		$	294,837		$	268,958		$	25,879		9.6
Commercial		146,538			146,235			303		0.2			264,008			253,522			10,486		4.1
Industrial		83,110			77,681			5,429		7.0			152,150			141,486			10,664		7.5
Other retail		(9,050	)		(17,179	)		8,129		47.3			(7,059	)		(18,264	)		11,205		61.4

Total Retail Revenues		370,692			355,041			15,651		4.4			703,936			645,702			58,234		9.0
Wholesale		78,999			65,651			13,348		20.3			161,747			151,396			10,351		6.8
Transmission (a)		36,314			41,172			(4,858	)	(11.8	)		72,943			68,069			4,874		7.2
Other		9,176			5,948			3,228		54.3			16,385			24,412			(8,027	)	(32.9	)

Total Revenues		495,181			467,812			27,369		5.9			955,011			889,579			65,432		7.4

OPERATING EXPENSES:
Fuel and purchased power		137,116			120,508			16,608		13.8			270,916			261,152			9,764		3.7
Operating and maintenance		121,810			139,810			(18,000	)	(12.9	)		242,983			261,978			(18,995	)	(7.3	)
Depreciation and amortization		67,107			63,814			3,293		5.2			134,037			122,028			12,009		9.8
Selling, general and administrative		48,154			53,638			(5,484	)	(10.2	)		94,080			101,619			(7,539	)	(7.4	)

Total Operating Expenses		374,187			377,770			(3,583	)	(0.9	)		742,016			746,777			(4,761	)	(0.6	)

INCOME FROM OPERATIONS		120,994			90,042			30,952		34.4			212,995			142,802			70,193		49.2

OTHER INCOME (EXPENSE):
Investment (losses) earnings		(655	)		5,322			(5,977	)	(112.3	)		1,102			4,530			(3,428	)	(75.7	)
Other income		1,041			1,153			(112	)	(9.7	)		1,895			4,410			(2,515	)	(57.0	)
Other expense		(2,403	)		(2,341	)		(62	)	(2.6	)		(6,897	)		(6,903	)		6		0.1

Total Other (Expense) Income		(2,017	)		4,134			(6,151	)	(148.8	)		(3,900	)		2,037			(5,937	)	(291.5	)

Interest expense		43,289			40,094			3,195		8.0			87,905			75,170			12,735		16.9

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		75,688			54,082			21,606		40.0			121,190			69,669			51,521		74.0
Income tax expense		21,158			15,696			5,462		34.8			34,979			20,098			14,881		74.0

INCOME FROM CONTINUING OPERATIONS		54,530			38,386			16,144		42.1			86,211			49,571			36,640		73.9
Results of discontinued operations, net of tax		—			—			—		—			—			32,978			(32,978	)	(100.0	)

NET INCOME		54,530			38,386			16,144		42.1			86,211			82,549			3,662		4.4
Less: Net income attributable to noncontrolling interests		1,219			—			1,219		(b	)		2,220			—			2,220		(b	)

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		53,311			38,386			14,925		38.9			83,991			82,549			1,442		1.7
Preferred dividends		242			242			—		—			485			485			—		—

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	53,069		$	38,144		$	14,925		39.1		$	83,506		$	82,064		$	1,442		1.8

BASIC EARNINGS PER SHARE:
Earnings available from continuing operations	$	0.47		$	0.35		$	0.12		34.3		$	0.75		$	0.45		$	0.30		66.7
Discontinued operations, net of tax		—			—			—		—			—			0.30			(0.30	)	(100.0	)

Earnings per common share, basic	$	0.47		$	0.35		$	0.12		34.3		$	0.75		$	0.75		$	—		—

(a)

Transmission: Reflects revenue derived from an SPP network transmission tariff. For the three months ended June 30, 2010, our SPP network transmission costs were $28.9 million. This amount, less $4.6 million retained by the SPP as administration cost, was returned to us as revenue. For the three months ended June 30, 2009, our SPP network transmission costs were $32.8 million with an administration cost of $3.7 million retained by the SPP. For the six months ended June 30, 2010, our SPP network transmission costs were $56.1 million. This amount, less $7.7 million retained by the SPP as administration cost, was returned to us as revenue. For the six months ended June 30, 2009, our SPP network transmission costs were $53.5 million with an administration cost of $7.6 million retained by the SPP.

(b)	Change greater than 1000%.

Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power needed to serve customers. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with a minimal impact on net income. For this reason, we believe gross margin, although a non-GAAP measurement, is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues less the sum of fuel and purchased power costs and SPP network transmission costs. Transmission costs reflect the costs of providing network transmission service. Accordingly, in calculating gross margin, we recognize the net value of this transmission activity as shown in the table immediately following. However, we record transmission costs as operating and maintenance expense on our consolidated statements of income. The following table summarizes our gross margin for the three and six months ended June 30, 2010 and 2009.


	Three Months Ended June 30,											Six Months Ended June 30,
	2010			2009			Change			% Change		2010			2009			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)											(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	150,094		$	148,304		$	1,790		1.2		$	294,837		$	268,958		$	25,879		9.6
Commercial		146,538			146,235			303		0.2			264,008			253,522			10,486		4.1
Industrial		83,110			77,681			5,429		7.0			152,150			141,486			10,664		7.5
Other retail		(9,050	)		(17,179	)		8,129		47.3			(7,059	)		(18,264	)		11,205		61.4

Total Retail Revenues		370,692			355,041			15,651		4.4			703,936			645,702			58,234		9.0
Wholesale		78,999			65,651			13,348		20.3			161,747			151,396			10,351		6.8
Transmission		36,314			41,172			(4,858	)	(11.8	)		72,943			68,069			4,874		7.2
Other		9,176			5,948			3,228		54.3			16,385			24,412			(8,027	)	(32.9	)

Total Revenues		495,181			467,812			27,369		5.9			955,011			889,579			65,432		7.4
Less: Fuel and purchased power expense		137,116			120,508			16,608		13.8			270,916			261,152			9,764		3.7
SPP network transmission costs		28,910			32,804			(3,894	)	(11.9	)		56,064			53,521			2,543		4.8

Gross Margin	$	329,155		$	314,500		$	14,655		4.7		$	628,031		$	574,906		$	53,125		9.2

The following table reflects changes in electricity sales for the three and six months ended June 30, 2010 and 2009. No electricity sales are shown for transmission or other as they are unrelated to the amount of electricity we sell.


	Three Months Ended June 30,						Six Months Ended June 30,
	2010	2009	Change		% Change		2010	2009	Change		% Change
	(Thousands of MWh)						(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,530	1,557	(27	)	(1.7	)	3,212	3,075	137		4.5
Commercial	1,908	1,903	5		0.3		3,575	3,515	60		1.7
Industrial	1,405	1,318	87		6.6		2,682	2,520	162		6.4
Other retail	23	22	1		4.5		44	43	1		2.3

Total retail	4,866	4,800	66		1.4		9,513	9,153	360		3.9
Wholesale	2,201	1,886	315		16.7		4,500	4,568	(68	)	(1.5	)

Total	7,067	6,686	381		5.7		14,013	13,721	292		2.1

The increase in gross margin for the three months ended June 30, 2010, compared to the same period last year was due primarily to the increase in total retail revenues, which was attributable primarily to higher industrial revenues. Industrial revenues increased due principally to greater electricity sales that we believe are the result of improving economic conditions.

The increase in gross margin for the six months ended June 30, 2010, compared to the same period last year was due principally to the increase in total retail revenues, which was the result primarily of price increases and higher electricity sales. Retail electricity sales increased due primarily to improved economic conditions and the effects of favorable weather, which particularly impacted residential electricity sales. Some of our commercial and industrial customers are beginning to experience increased orders and production, although not to levels experienced prior to the economic downturn. Offsetting the increase in total retail revenues was a decrease in other revenues due principally to our having settled forward contracts for the sale of electricity on favorable terms during the six months ended June 30, 2009. We did not record similar settlements during the same period this year.

Income from operations is the most directly comparable measure to gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the three and six months ended June 30, 2010 and 2009.


	Three Months Ended June 30,									Six Months Ended June 30,
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(Dollars In Thousands)									(Dollars In Thousands)
Gross margin	$	329,155	$	314,500	$	14,655		4.7		$	628,031	$	574,906	$	53,125		9.2
Add: SPP network transmission costs		28,910		32,804		(3,894	)	(11.9	)		56,064		53,521		2,543		4.8
Less: Operating and maintenance expense		121,810		139,810		(18,000	)	(12.9	)		242,983		261,978		(18,995	)	(7.3	)
Depreciation and amortization expense		67,107		63,814		3,293		5.2			134,037		122,028		12,009		9.8
Selling, general and administrative expense		48,154		53,638		(5,484	)	(10.2	)		94,080		101,619		(7,539	)	(7.4	)

Income from operations	$	120,994	$	90,042	$	30,952		34.4		$	212,995	$	142,802	$	70,193		49.2

Operating Expenses and Other Income and Expense Items


	Three Months Ended June 30,									Six Months Ended June 30,
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(Dollars In Thousands)
Operating and maintenance expense	$	121,810	$	139,810	$	(18,000	)	(12.9	)	$	242,983	$	261,978	$	(18,995	)	(7.3	)

Operating and maintenance expense decreased for the three and six months ended June 30, 2010, compared to the same periods last year due primarily to reductions of $5.1 million and $10.2 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities.” Also contributing to the decrease for both periods was the recognition of a $5.0 million reduction in our maximum liability for environmental remediation costs related to former manufactured gas sites in Missouri. See Note 7 of the Notes to Condensed Consolidated Financial Statements, “Commitments and Contingencies,” for additional information. Lower SPP network transmission costs of $3.9 million, which are reflected in the $4.9 million decrease in transmission revenues, further contributed to the decrease for the three months ended June 30, 2010.


	Three Months Ended June 30,							Six Months Ended June 30,
	2010		2009		Change		% Change	2010		2009		Change		% Change
	(Dollars In Thousands)
Depreciation and amortization expense	$	67,107	$	63,814	$	3,293	5.2	$	134,037	$	122,028	$	12,009	9.8

Depreciation and amortization expense increased for the three months ended June 30, 2010, compared to the same period last year due primarily to depreciation expense associated with a higher plant balance. For the six months ended June 30, 2010, depreciation and amortization expense increased primarily to reflect the addition of wind generation facilities, new generating plant, air quality controls at our power plants as well as other general plant additions. In addition, during the three and six months ended June 30, 2010, we recorded additional depreciation expense of $1.5 million and $3.0 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities.”


	Three Months Ended June 30,									Six Months Ended June 30,
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(Dollars In Thousands)
Selling, general and administrative expense	$	48,154	$	53,638	$	(5,484	)	(10.2	)	$	94,080	$	101,619	$	(7,539	)	(7.4	)

The decreases in selling, general and administrative expense for the three and six months ended June 30, 2010, compared to the same periods last year were due principally to lower pension and other employee benefits costs of $4.3 million and $7.6 million, respectively. The lower pension costs were attributable primarily to our having recorded credits to expense of $3.2 million and $6.2 million, respectively, in accordance with a September 2009 KCC order allowing us to establish a regulatory asset or liability for the cumulative difference between pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices.


	Three Months Ended June 30,										Six Months Ended June 30,
	2010			2009		Change			% Change		2010		2009		Change			% Change
	(Dollars In Thousands)
Investment (losses) earnings	$	(655	)	$	5,322	$	(5,977	)	(112.3	)	$	1,102	$	4,530	$	(3,428	)	(75.7	)

Investment earnings decreased for the three and six months ended June 30, 2010, compared to the same periods last year due principally to our having recorded losses of $2.6 million and $1.1 million, respectively, on investments held in a trust to fund retirement benefits. We recorded gains on these investments of $5.3 million and $2.9 million, respectively, in the same periods of 2009. Offsetting the decrease for the three months ended June 30, 2010, was our having recorded $1.9 million of interest pursuant to a settlement agreement related to amended income tax returns we filed to claim credits for investments and jobs creation within the state of Kansas.


	Three Months Ended June 30,									Six Months Ended June 30,
	2010		2009		Change			% Change		2010		2009		Change			% Change
	(Dollars In Thousands)
Other income	$	1,041	$	1,153	$	(112	)	(9.7	)	$	1,895	$	4,410	$	(2,515	)	(57.0	)

Other income decreased for the six months ended June 30, 2010, compared to the same period last year due principally to a $2.2 million decrease in equity AFUDC. The decrease in equity AFUDC was attributable to reduced construction activity due to the completion of large construction projects.


	Three Months Ended June 30,							Six Months Ended June 30,
	2010		2009		Change		% Change	2010		2009		Change		% Change
	(Dollars In Thousands)
Interest expense	$	43,289	$	40,094	$	3,195	8.0	$	87,905	$	75,170	$	12,735	16.9

Interest expense increased for the three and six months ended June 30, 2010, compared to the same periods last year due primarily to our having recorded additional interest expense of $3.2 million and $6.6 million, respectively, as a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” and interest on additional debt issued in 2009 to fund capital investments. Contributing to the increase for the six months ended June 30, 2010, was our having recorded $1.2 million less for capitalized interest as a result of completing large construction projects.


	Three Months Ended June 30,							Six Months Ended June 30,
	2010		2009		Change		% Change	2010		2009		Change		% Change
	(Dollars In Thousands)
Income tax expense	$	21,158	$	15,696	$	5,462	34.8	$	34,979	$	20,098	$	14,881	74.0

Income tax expense increased for the three and six months ended June 30, 2010, compared to the same periods last year due principally to higher income from continuing operations before income taxes.

FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of June 30, 2010, compared to December 31, 2009.

As a result of the consolidation of the VIEs discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” we recorded property, plant and equipment of variable interest entities, net, of $350.8 million, current maturities of long-term debt of variable interest entities of $29.1 million and long-term debt of variable interest entities, net, of $297.9 million.

Tax receivable decreased $45.2 million due principally to the receipt of $34.9 million from the IRS related to the settlement of tax years 1999 and 2004 through 2007. In addition, we received $11.8 million from the Kansas Department of Revenue in connection with our 2006 and 2007 tax years.

The fair market value of net energy marketing contracts increased $11.2 million to $15.6 million at June 30, 2010. This was due primarily to the fair value measurement of a fuel supply contract having increased by $9.8 million. The portion of this fuel supply contract that was outstanding the entire period increased $5.7 million due to increases in the market price of coal. Further increasing the fair value measurement of this fuel supply contract was the settlement of a $4.1 million net loss position during the period. Changes in the fair value measurements of our fuel supply contracts have a corresponding change in net regulatory assets.

Regulatory assets, net of regulatory liabilities, decreased $57.3 million to $657.7 million at June 30, 2010, from $715.0 million at December 31, 2009. Total regulatory assets decreased $45.3 million due primarily to the $11.5 million amortization of deferred storm costs, $10.5 million decrease in previously deferred fuel expense, $7.5 million decrease in deferred employee benefit costs, $5.6 million decrease in amounts due from customers for future income taxes and $5.6 million amortization of previously deferred amounts for the Wolf Creek outage. Regulatory liabilities increased $12.0 million due primarily to a $12.5 million increase in removal costs for amounts included in our prices, but not yet spent to remove retired assets, and a $4.9 million increase resulting from the increase in the fair value measurement of fuel supply contracts. Increases in regulatory liabilities were partially offset by a $13.7 million decrease in our refund obligation related to the RECA and a $3.4 million decrease in the fair value of our NDT assets.

Unamortized investment tax credits increased $26.8 million due principally to incentives we earned related to investments in plant within the state of Kansas

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy’s revolving credit facility and access to capital markets. We believe we will have sufficient cash to meet our day-to-day requirements including, among other items, funding our operations, making interest payments and paying dividends. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in “– Operating Results” above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets.

Capital Resources

As of July 27, 2010, Westar Energy had a $730.0 million revolving credit facility under which $268.2 million had been borrowed and an additional $22.4 million of letters of credit had been issued.

On January 27, 2010, FERC approved our request for authority to issue short-term securities and pledge KGE mortgage bonds in order to increase the size of Westar Energy’s revolving credit facility to $1.0 billion. We have not yet exercised our authority to increase the size of the facility.

Common Stock Issuance

Cash Flows from Operating Activities

Operating activities provided $238.8 million of cash in the six months ended June 30, 2010, compared with cash provided of $216.0 million during the same period of 2009. This increase was due primarily to our having received $44.3 million in net tax refunds during the six months ended June 30, 2010, compared to $9.1 million in net tax refunds for the same period last year. Also contributing to the increase were our having received approximately $30.7 million more in customer receipts and our having paid $9.8 million less for fuel and purchased power during the six months ended June 30, 2010. Partially offsetting these increases was our having paid $61.9 million more for interest on corporate-owned life insurance (COLI) policies during the six months ended June 30, 2010, compared to the same period last year as a result of a policy change in the second quarter of 2009 under which we no longer pay interest on COLI policies in advance.

Cash Flows used in Investing Activities

Investing activities used $255.8 million of cash in the six months ended June 30, 2010, compared to $355.4 million during the same period of 2009. We spent $237.6 million in the six months ended June 30, 2010, and $338.8 million in the same period of 2009 on additions to property, plant and equipment.

Cash Flows from Financing Activities

Financing activities provided $16.4 million of cash in the six months ended June 30, 2010, compared to $121.4 million of cash provided from financing activities in the same period of 2009. In the six months ended June 30, 2010, borrowings against the cash surrender value of COLI provided $71.3 million and proceeds from the issuance of common stock provided $27.3 million. We used cash to pay $63.7 million in dividends and to repay $10.5 million of long-term debt of VIEs. 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. The decrease in cash provided from financing activities was due primarily to a reduction in our financing needs as a result of our having completed large construction projects.

Debt Covenants

We remain in compliance with the debt covenants described in our 2009 Form 10-K.

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.

On June 1, 2010, and May 19, 2010, respectively, Fitch and Moody’s revised their outlooks for Westar Energy and KGE credit ratings to positive from stable. Additionally, on April 27, 2010, S&P upgraded its credit ratings for Westar Energy’s and KGE’s first mortgage bonds/senior secured debt from BBB to BBB+. S&P also upgraded its credit rating for Westar Energy’s unsecured debt from BBB- to BBB and changed its outlook for the ratings from positive to stable.

As of July 27, 2010, 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	Positive
S&P	BBB+	BBB+	BBB	Stable
Fitch	BBB+	BBB+	BBB	Positive

In general, less favorable credit ratings make borrowing more difficult and costly. Under Westar Energy’s revolving credit facility our cost of borrowing is determined in part by credit ratings. However, Westar Energy’s 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, 2010, and December 31, 2009, was $5.1 million and $1.4 million, respectively, for which we had posted collateral of $1.0 million as of June 30, 2010, and no collateral as of December 31, 2009. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2010, or December 31, 2009, we would have been required to provide to our counterparties $0.1 million of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Pension Contribution

During the six months ended June 30, 2010, we contributed $16.8 million to the Westar Energy pension trust and funded $1.8 million of Wolf Creek’s pension plan contribution.

OFF-BALANCE SHEET ARRANGEMENTS

Other than the consolidation of VIEs as discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” from December 31, 2009, through June 30, 2010, there have been no material changes in our off-balance sheet arrangements. For additional information, see our 2009 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2009, through June 30 2010, there have been no material changes outside the ordinary course of business in our contractual obligations and commercial commitments. For additional information, see our 2009 Form 10-K.

OTHER INFORMATION

Increases in Prices

On June 11, 2010, the KCC issued a final order approving an adjustment to our prices that we made earlier this year. The adjustment includes updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million.

Fair Value of Energy Marketing and Fuel Contracts

The table below shows the fair value of energy marketing contracts outstanding as of June 30, 2010.


	Fair Value of Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2009 (a)	$	4,441
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		4,469
Changes in fair value of contracts outstanding at the beginning and end of the period		6,559
Fair value of new contracts entered into during the period		138

Fair value of contracts outstanding as of June 30, 2010 (b)	$	15,607



(a) Approximately $7.6 million and $6.0 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.
(b) Approximately $0.4 million and $10.9 million of the fair value of energy marketing contracts were 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, 2010, 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)	$	(11	)	$	(11	)	$	—		$	—		$	—
Prices provided by other external sources (swaps and forwards)		15,113			3,998			7,654			3,461			—
Prices based on option pricing models (options and other) (a)		505			598			(41	)		(52	)		—

Total fair value of contracts outstanding	$	15,607		$	4,585		$	7,613		$	3,409		$	—

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

New Accounting Pronouncements

Consolidation Guidance for Variable Interest Entities

In June 2009, FASB issued guidance that amends the consolidation guidance for VIEs. The amended guidance requires a qualitative assessment rather than a quantitative assessment in determining the primary beneficiary of a VIE and significantly changes the criteria to consider in determining the primary beneficiary. Pursuant to the amended guidance, there is no exclusion, or “grandfathering,” of VIEs that were not consolidated under prior guidance. This amended guidance is effective for annual reporting periods beginning after November 15, 2009. We adopted the guidance effective January 1, 2010, and, as a result, began consolidating certain VIEs that hold assets we lease. See Note 12 of the Notes to Condensed Consolidated Financial Statements, “Variable Interest Entities,” for additional information.

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. From December 31, 2009, to June 30, 2010, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2009 Form 10-K for additional information.

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, 2010, 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, 2009, through June 30, 2010. For additional information, see our 2009 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

In addition to information previously included in one or more Current Reports on Form 8-K, during the three-month period ended June 30, 2010, Westar Energy entered into forward transactions pursuant to the forward sale agreement, dated April 2, 2010, between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on April 2, 2010) and the Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.3 to the Form S-3 filed on April 2, 2010) in respect to an aggregate of approximately 0.9 million shares of Westar Energy common stock.

In connection with the forward transactions, Westar did not receive any proceeds from the sale of borrowed shares of its common stock by BNY Mellon Capital Markets, LLC. Westar expects to receive proceeds from the sale of such shares, subject to certain adjustments, upon future physical settlement(s) of the forward transactions pursuant to the terms of the forward sale agreement. If Westar elects to cash settle or net share settle the forward transactions, it may not receive any proceeds (in the case of cash settlement) or shares of its common stock (in the case of net share settlement) pursuant to the terms of the forward sale agreement.

The forward transactions were entered into pursuant to the terms of the letter dated October 6, 2003, submitted by Robert W. Reeder and Leslie N. Silverman to Paula Dubberly of the staff of the Securities and Exchange Commission (Staff), to which the Staff responded in an interpretive letter dated October 9, 2003. As required by such letter, the shares of Westar common stock sold by BNY Mellon Capital markets, LLC to hedge the forward transaction were sold pursuant to an effective Westar registration statement (registration No. 333-165889), which was filed on April 2, 2010.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.

REMOVED AND RESERVED

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS


31(a)		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended June 30, 2010

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, 2010

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2010 (furnished and not to be considered filed as part of the Form 10-Q)

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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 5, 2010	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle,
			Executive Vice President and Chief Financial Officer