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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, 2011

¨	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		115,812,605 shares
(Class)		(Outstanding at July 26, 2011)

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		34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		46

Item 4.	Controls and Procedures		47

PART II. Other Information

Item 1.	Legal Proceedings		47

Item 1A.	Risk Factors		47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		48

Item 3.	Defaults Upon Senior Securities		48

Item 4.	Removed and Reserved		48

Item 5.	Other Information		48

Item 6.	Exhibits		48

Signature			49

GLOSSARY OF TERMS

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


Abbreviation or Acronym		Definition
2010 Form 10-K		Annual Report on Form 10-K for the year ended December 31, 2010
AFUDC		Allowance for Funds Used During Construction
BACT		Best available control technology
CSAPR		Cross-State Air Pollution Rule
ECRR		Environmental Cost Recovery Rider
EPA		Environmental Protection Agency
EPS		Earnings per share
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings
GAAP		Generally Accepted Accounting Principles
GHG		Greenhouse gas
JEC		Jeffrey Energy Center
KCC		Kansas Corporation Commission
KCPL		Kansas City Power & Light Company
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
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen Oxide
NRC		Nuclear Regulatory Commission
ONEOK		ONEOK, Inc.
OTC		Over-the-counter
PSD		Prevention of Significant Deterioration program
RECA		Retail energy cost adjustment
RSUs		Restricted share units
S&P		Standard & Poor’s Ratings Services
SCR		Selective catalytic reduction
SO₂		Sulfur dioxide
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,” “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,

•

the impact of frequently changing laws and regulations relating to air emissions, water emissions, waste management and other environmental matters,

•

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,

•

additional regulation due to Nuclear Regulatory Commission (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek’s performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,

•

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 potential 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, 2010 (2010 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 2010 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 2010 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, 2011		December 31, 2010
	June 30, 2011		December 31, 2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,282	$	928
Accounts receivable, net of allowance for doubtful accounts of $5,657 and $5,729, respectively		269,056		227,700
Inventories and supplies, net		223,932		206,867
Energy marketing contracts		11,443		13,005
Taxes receivable		12,050		16,679
Deferred tax assets		8,637		30,248
Prepaid expenses		12,926		12,413
Regulatory assets		99,048		73,480
Other		21,924		20,289

Total Current Assets		664,298		601,609

PROPERTY, PLANT AND EQUIPMENT, NET		6,174,126		5,964,439

PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET		339,253		345,037

OTHER ASSETS:
Regulatory assets		783,627		787,585
Nuclear decommissioning trust		134,547		126,990
Energy marketing contracts		8,135		9,472
Other		219,162		244,506

Total Other Assets		1,145,471		1,168,553

TOTAL ASSETS	$	8,323,148	$	8,079,638

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt	$	—	$	61
Current maturities of long-term debt of variable interest entities		26,991		30,155
Short-term debt		471,000		226,700
Accounts payable		173,225		187,954
Accrued taxes		50,871		45,534
Energy marketing contracts		8,563		9,670
Accrued interest		51,444		77,771
Regulatory liabilities		35,512		28,284
Other		154,480		176,717

Total Current Liabilities		972,086		782,846

LONG-TERM LIABILITIES:
Long-term debt, net		2,491,015		2,490,871
Long-term debt of variable interest entities, net		270,034		278,162
Deferred income taxes		1,054,666		1,102,625
Unamortized investment tax credits		155,209		101,345
Regulatory liabilities		137,579		135,754
Deferred regulatory gain from sale-leaseback		94,793		97,541
Accrued employee benefits		437,770		483,769
Asset retirement obligations		129,458		125,999
Energy marketing contracts		—		10
Other		89,829		66,878

Total Long-Term Liabilities		4,860,353		4,882,954

COMMITMENTS AND CONTINGENCIES (See Notes 8 and 9)
TEMPORARY EQUITY		—		3,465

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 275,000,000 shares and 150,000,000 shares, respectively; issued and outstanding 115,717,345 shares and 112,128,068 shares, respectively		578,586		560,640
Paid-in capital		1,458,490		1,398,580
Retained earnings		425,273		423,647

Total Westar Energy Shareholders’ Equity		2,483,785		2,404,303

Noncontrolling Interests		6,924		6,070

Total Equity		2,490,709		2,410,373

TOTAL LIABILITIES AND EQUITY	$	8,323,148	$	8,079,638

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,
	2011			2010
REVENUES	$	524,892		$	495,181

OPERATING EXPENSES:
Fuel and purchased power		152,973			137,116
Operating and maintenance		137,254			121,810
Depreciation and amortization		71,089			67,107
Selling, general and administrative		55,970			48,154

Total Operating Expenses		417,286			374,187

INCOME FROM OPERATIONS		107,606			120,994

OTHER INCOME (EXPENSE):
Investment earnings (losses)		1,374			(655	)
Other income		2,557			1,041
Other expense		(3,113	)		(2,403	)

Total Other Income (Expense)		818			(2,017	)

Interest expense		43,300			43,289

INCOME BEFORE INCOME TAXES		65,124			75,688
Income tax expense		19,599			21,158

NET INCOME		45,525			54,530
Less: Net income attributable to noncontrolling interests		1,396			1,219

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		44,129			53,311
Preferred dividends		242			242

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	43,887		$	53,069

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2)	$	0.38		$	0.47
Average equivalent common shares outstanding		114,908,123			111,522,803
DIVIDENDS DECLARED PER COMMON SHARE	$	0.32		$	0.31

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,
	2011			2010
REVENUES	$	1,006,611		$	955,011

OPERATING EXPENSES:
Fuel and purchased power		287,157			270,916
Operating and maintenance		274,606			242,983
Depreciation and amortization		141,348			134,037
Selling, general and administrative		104,734			94,080

Total Operating Expenses		807,845			742,016

INCOME FROM OPERATIONS		198,766			212,995

OTHER INCOME (EXPENSE):
Investment earnings		3,342			1,102
Other income		4,806			1,895
Other expense		(8,482	)		(6,897	)

Total Other Expense		(334	)		(3,900	)

Interest expense		86,838			87,905

INCOME BEFORE INCOME TAXES		111,594			121,190
Income tax expense		33,112			34,979

NET INCOME		78,482			86,211
Less: Net income attributable to noncontrolling interests		2,770			2,220

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		75,712			83,991
Preferred dividends		485			485

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	75,227		$	83,506

BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Basic earnings per common share	$	0.66		$	0.75
Diluted earnings per common share	$	0.65		$	0.75
Average equivalent common shares outstanding		114,396,909			111,224,830
DIVIDENDS DECLARED PER COMMON SHARE	$	0.64		$	0.62

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,
	2011			2010
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	78,482		$	86,211
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		141,348			134,037
Amortization of nuclear fuel		5,913			12,832
Amortization of deferred regulatory gain from sale-leaseback		(2,748	)		(2,748	)
Amortization of corporate-owned life insurance		12,041			9,348
Non-cash compensation		4,889			5,262
Net changes in energy marketing assets and liabilities		417			(805	)
Accrued liability to certain former officers		1,180			802
Net deferred income taxes and credits		26,645			56,227
Stock-based compensation excess tax benefits		(727	)		(411	)
Allowance for equity funds used during construction		(3,421	)		(1,084	)
Changes in working capital items:
Accounts receivable		(44,249	)		(56,536	)
Inventories and supplies		(16,682	)		(9,259	)
Prepaid expenses and other		(28,608	)		10,403
Accounts payable		17,013			52,422
Accrued taxes		10,173			51,692
Other current liabilities		(85,444	)		(91,108	)
Changes in other assets		(13,673	)		19,340
Changes in other liabilities		(31,102	)		(37,807	)

Cash Flows from Operating Activities		71,447			238,818

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment		(345,550	)		(237,645	)
Purchase of securities within trusts		(34,560	)		(166,916	)
Sale of securities within trusts		33,821			167,209
Investment in corporate-owned life insurance		(18,845	)		(18,884	)
Proceeds from investment in corporate-owned life insurance		744			875
Proceeds from federal grant		3,746			—
Investment in affiliated company		(909	)		—
Other investing activities		2,354			(395	)

Cash Flows used in Investing Activities		(359,199	)		(255,756	)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net		242,091			(2,000	)
Retirements of long-term debt		(191	)		(980	)
Retirements of long-term debt of variable interest entities		(10,903	)		(10,450	)
Repayment of capital leases		(931	)		(1,174	)
Borrowings against cash surrender value of corporate-owned life insurance		64,875			71,309
Repayment of borrowings against cash surrender value of corporate-owned life insurance		(3,020	)		(2,233	)
Stock-based compensation excess tax benefits		727			411
Issuance of common stock		69,220			27,288
Distributions to shareholders of noncontrolling interests		(1,916	)		(2,094	)
Cash dividends paid		(67,846	)		(63,676	)

Cash Flows from Financing Activities		292,106			16,401

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		4,354			(537	)
CASH AND CASH EQUIVALENTS:
Beginning of period		928			3,860

End of period	$	5,282		$	3,323

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										Noncontrolling interests			Total equity
	Cumulative preferred stock		Common stock		Paid-in capital			Retained earnings			Noncontrolling interests			Total equity
Balance at December 31, 2009	$	21,436	$	545,360	$	1,339,790		$	360,199		$	—		$	2,266,785

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

Balance at December 31, 2010	$	21,436	$	560,640	$	1,398,580		$	423,647		$	6,070		$	2,410,373

Net income		—		—		—			75,712			2,770			78,482
Issuance of common stock		—		17,946		61,102			—			—			79,048
Preferred dividends		—		—		—			(485	)		—			(485	)
Dividends on common stock		—		—		—			(73,601	)		—			(73,601	)
Transfer from temporary equity		—		—		3,465			—			—			3,465
Amortization of restricted stock		—		—		4,267			—			—			4,267
Stock compensation and tax benefit		—		—		(8,924	)		—			—			(8,924	)
Distributions to shareholders of noncontrolling interests		—		—		—			—			(1,916	)		(1,916	)

Balance at June 30, 2011	$	21,436	$	578,586	$	1,458,490		$	425,273		$	6,924		$	2,490,709

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 688,000 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. 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) of which we maintain a controlling interest or are the primary beneficiary reported as a single operating segment. 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 consolidated financial statements and notes included in our 2010 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, valuation of investments, valuation of our energy marketing portfolio, forecasted fuel costs included in our retail energy cost adjustment (RECA) billed to customers, income taxes, pension and other post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, 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, 2011, 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,
	2011		2010		2011		2010
	(Dollars in Thousands)
Borrowed funds	$	1,562	$	948	$	3,062	$	1,692
Equity funds		1,669		630		3,421		1,084

Total	$	3,231	$	1,578	$	6,483	$	2,776

Average AFUDC Rates		4.2%		2.3%		4.4%		2.3%

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. As a result, 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 equivalent common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements, RSUs that do not have nonforfeitable rights to dividend equivalents and stock options. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	45,525	$	54,530	$	78,482	$	86,211
Less: Net income attributable to noncontrolling interests		1,396		1,219		2,770		2,220

Net income attributable to Westar Energy		44,129		53,311		75,712		83,991
Less: Preferred dividends		242		242		485		485
Net income allocated to RSUs		19		298		138		466

Net income allocated to common stock	$	43,868	$	52,771	$	75,089	$	83,040

Weighted average equivalent common shares outstanding – basic		114,908,123		111,522,803		114,396,909		111,224,830
Effect of dilutive securities:
RSUs		182,384		118,083		169,165		73,190
Forward sale agreements		1,846,084		86,431		1,779,107		29,387
Employee stock options		—		—		—		107

Weighted average equivalent common shares outstanding – diluted (a)		116,936,591		111,727,317		116,345,181		111,327,514

Earnings per common share, basic	$	0.38	$	0.47	$	0.66	$	0.75
Earnings per common share, diluted	$	0.38	$	0.47	$	0.65	$	0.75

(a)	For the three and six months ended June 30, 2011, and three months ended June 30, 2010, we did not have any antidilutive shares. For the six months ended June 30, 2010, potentially dilutive shares not included in the denominator because they are antidilutive totaled 889 shares.

Supplemental Cash Flow Information


	Six Months Ended June 30,
	2011		2010
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	72,225	$	73,221
Interest on financing activities of VIEs		9,335		10,335
Income taxes, net of refunds		1,113		(44,272	)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		73,989		23,763
Property, plant and equipment additions of VIEs		—		356,964
Jeffrey Energy Center (JEC) 8% leasehold interest		—		(108,706	)
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans		7,909		8,361
Debt of VIEs		—		337,951
Capital lease for JEC 8% leasehold interest		—		(106,423	)
Assets acquired through capital leases		41,901		321

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

Values of Financial and Derivative Instruments

GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of fair value assets and liabilities within the fair value hierarchy levels. 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 measured at net asset value, 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 electricity supply contracts.

We record 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.

All of our level 2 investments, whether in the nuclear decommissioning trust (NDT) or our trading securities portfolio, are held in investment funds that are measured using daily net asset values as reported by the fund managers. In addition, we maintain certain level 3 investments in private equity 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. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. 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, 2011, and December 31, 2010.


	As of June 30, 2011				As of December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,373,243	$	2,493,903	$	2,373,373	$	2,570,648
Fixed-rate debt of VIEs		294,993		340,001		308,317		341,328

Recurring Fair Value Measurements

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


	Level 1		Level 2		Level 3		Total
	(In Thousands)
As of June 30, 2011
Assets:
Energy Marketing Contracts	$	—	$	1,858	$	17,720	$	19,578
Nuclear Decommissioning Trust:
Domestic equity		—		53,373		3,111		56,484
International equity		—		26,879		—		26,879
Core bonds		—		21,736		—		21,736
High-yield bonds		—		9,415		—		9,415
Emerging market bonds		—		5,643		—		5,643
Combination debt/equity fund		—		7,665		—		7,665
Real estate securities		—		—		3,296		3,296
Cash equivalents		3,429		—		—		3,429

Total Nuclear Decommissioning Trust		3,429		124,711		6,407		134,547

Trading Securities:
Domestic equity		—		21,975		—		21,975
International equity		—		5,344		—		5,344
Core bonds		—		14,600		—		14,600

Total Trading Securities		—		41,919		—		41,919

Treasury Yield Hedges		—		6,530		—		6,530

Total Assets Measured at Fair Value	$	3,429	$	175,018	$	24,127	$	202,574

Liabilities:
Energy Marketing Contracts	$	—	$	1,736	$	6,827	$	8,563

As of December 31, 2010
Assets:
Energy Marketing Contracts	$	2,432	$	6,258	$	13,787	$	22,477
Nuclear Decommissioning Trust:
Domestic equity		—		60,586		2,867		63,453
International equity		—		18,966		—		18,966
Core bonds		—		31,906		—		31,906
High-yield bonds		—		9,267		305		9,572
Real estate securities		—		—		3,049		3,049
Cash equivalents		44		—		—		44

Total Nuclear Decommissioning Trust		44		120,725		6,221		126,990

Trading Securities:
Domestic equity		—		21,207		—		21,207
International equity		—		5,128		—		5,128
Core bonds		—		13,077		—		13,077

Total Trading Securities		—		39,412		—		39,412

Treasury Yield Hedges		—		7,711		—		7,711

Total Assets Measured at Fair Value	$	2,476	$	174,106	$	20,008	$	196,590

Liabilities:
Energy Marketing Contracts	$	1,888	$	5,820	$	1,972	$	9,680

We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of June 30, 2011, we had recorded $0.1 million for our right to reclaim cash collateral and $1.0 million for our obligation to return cash collateral. As of December 31, 2010, we had no right to reclaim cash collateral and had recorded $0.7 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, 2011.


	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, 2011	$	12,006		$	3,058		$	—		$	3,049		$	18,113
Total realized and unrealized gains (losses) included in:
Earnings (a)		(68	)		—			—			—			(68	)
Regulatory assets		(373	)(b)		—			—			—			(373	)
Regulatory liabilities		(65	)(b)		(133	)		—			248			50
Purchases		(329	)		189			—			23			(117	)
Sales		(987	)		(3	)		—			(24	)		(1,014	)
Settlements		709			—			—			—			709

Balance as of June 30, 2011	$	10,893		$	3,111		$	—		$	3,296		$	17,300

Balance as of December 31, 2010	$	11,815		$	2,867		$	305		$	3,049		$	18,036
Total realized and unrealized gains (losses) included in:
Earnings (a)		(266	)		—			—			—			(266	)
Regulatory assets		(391	)(b)		—			—			—			(391	)
Regulatory liabilities		535	(b)		(101	)		—			248			682
Purchases		(1,072	)		361			—			23			(688	)
Sales		(93	)		(16	)		(305	)		(24	)		(438	)
Settlements		365			—			—			—			365

Balance as of June 30, 2011	$	10,893		$	3,111		$	—		$	3,296		$	17,300

(a)	Unrealized and realized gains and losses included in earnings 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, 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 are reported in revenues.

(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, 2011 and 2010, attributed to level 3 assets and liabilities.


	Three Months Ended June 30, 2011
	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)	$	(33	)	$	—		$	—	$	—	$	(33	)
Regulatory assets		(252	)(b)		—			—		—		(252	)
Regulatory liabilities		(89	)(b)		(136	)		—		225		—

Total	$	(374	)	$	(136	)	$	—	$	225	$	(285	)


	Six Months Ended June 30, 2011
Total unrealized gains (losses) included in:
Earnings (a)	$	(305	)	$	—		$	—	$	—	$	(305	)
Regulatory assets		(261	)(b)		—			—		—		(261	)
Regulatory liabilities		511	(b)		(117	)		—		225		619

Total	$	(55	)	$	(117	)	$	—	$	225	$	53

(a)	Unrealized gains and losses included in earnings are reported in revenues.

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


	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 are reported in revenues.

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

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


	As of June 30, 2011				As of December 31, 2010				As of June 30, 2011
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	3,111	$	2,162	$	2,867	$	2,523	(a)	(a)
High-yield bonds		—		—		305		—	(b)	(b)
Real estate securities		3,296		—		3,049		—	(c)	(c)

Total Nuclear Decommissioning Trust	$	6,407	$	2,162	$	6,221	$	2,523

Trading Securities:
Domestic equity	$	21,975	$	—	$	21,207	$	—	Upon Notice	1 day
International equity		5,344		—		5,128		—	Upon Notice	1 day
Core bonds		14,600		—		13,077		—	Upon Notice	1 day

Total Trading Securities		41,919		—		39,412		—

Total	$	48,326	$	2,162	$	45,633	$	2,523

(a)

This investment is in two long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. One fund has begun to make distributions and we expect the other to begin in 2013.

(b)	We completely settled this fund in the first quarter of 2011.

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

Derivative Instruments

Cash Flow Hedges

In 2010, we entered into treasury yield hedge transactions for a total notional amount of $100.0 million in an attempt to manage our interest rate risk associated with a future anticipated issuance of fixed-rate debt, which is probable to occur within 18 months of the initial treasury yield hedge transaction date. Such transactions are designated and qualify as cash flow hedges and are measured at fair value by estimating the net present value of a series of payments using market-based models with observable inputs, such as the spread between the 30-year U.S. Treasury bill yield and the contracted, fixed yield. As a result of regulatory accounting treatment, we report the effective portion of the gain or loss on these derivative instruments as a regulatory liability or regulatory asset and will amortize such amounts to interest expense over the life of the related debt. We record hedge ineffectiveness gains in other income and hedge ineffectiveness losses in other expense on our consolidated statements of income. As of June 30, 2011, and December 31, 2010, the fair value of the treasury yield hedge transactions was $6.5 million and $7.7 million, respectively, which we recorded in other current assets and other assets, respectively, on our consolidated balance sheets. We also recorded these same amounts in current regulatory liabilities and long-term regulatory liabilities, respectively, on our consolidated balance sheets to reflect the effective portion of the gains on these transactions as of June 30, 2011, and December 31, 2010.

Commodity Contracts

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, swaps and physical commodity contracts.

We classify these commodity 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.

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

Commodity Derivatives Not Designated as Hedging Instruments as of June 30, 2011


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	$	11,443	Energy marketing contracts	$	8,563
Other assets:
Energy marketing contracts		8,135

Total	$	19,578

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 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	$	13,005	Energy marketing contracts	$	9,670
Other assets:			Long-term liabilities:
Energy marketing contracts		9,472	Energy marketing contracts		10

Total	$	22,477	Total	$	9,680

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, 2011 and 2010.


	Three Months Ended June 30, 2011					Six Months Ended June 30, 2011
Location	Net Gain Recognized		Net Loss Recognized			Net Gain Recognized			Net Loss Recognized
	(In thousands)
Revenues increase (decrease)	$	956	$	—		$	—		$	(599	)
Regulatory liabilities decrease		—		(994	)		—			(1,207	)

	Three Months Ended June 30, 2010					Six Months Ended June 30, 2010
Revenues decrease	$	—	$	(946	)	$	—		$	(1,810	)
Regulatory assets increase (decrease)		—		39			(7,155	)		—
Regulatory liabilities increase		1,548		—			4,927			—

As of June 30, 2011, and December 31, 2010, we had under contract the following commodity derivatives.


		Net Quantity as of
	Unit of Measure	June 30, 2011		December 31, 2010
Electricity	MWh		2,654,703		2,791,966
Natural Gas	MMBtu		2,664,000		1,150,000

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. Our prices, consolidated financial results and cash flows are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to these market risks through regulatory, 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.

Interest Rate Risk

We have entered into fixed and variable rate debt obligations. We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps.

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 constraints 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, 2011, and December 31, 2010, was $6.6 million and $1.6 million, respectively, for which we had posted $1.6 million of collateral, including independent amounts, as of June 30, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2011, and December 31, 2010, we would have been required to provide to our counterparties $2.0 million and $1.6 million, respectively, 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 realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We have equity and debt investments in a trust used to fund retirement benefits that we classify as trading securities. We include 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, 2011, we recorded gains on these securities of $0.6 million and $2.5 million, respectively. We recorded unrealized losses of $2.6 million and $1.1 million, respectively, during the three and six months ended June 30, 2010.

Available-for-Sale Securities

We hold investments in equity, debt and real estate 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, 2011, and December 31, 2010. At June 30, 2011, investments in the NDT fund were allocated 42% to domestic equity, 20% to international equity, 16% to core bonds, 7% to high-yield bonds, 4% to emerging market bonds, 6% to combined debt/equity funds, 2% to real estate securities and 3% to cash and cash equivalents. The core bond fund has a requirement 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, 2011, the fair value of available-for-sale debt securities in the core, high-yield and emerging market bond funds was $36.8 million. As of June 30, 2011, we had not invested in debt securities outside of investment funds.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $0.3 million and $1.3 million, respectively, during the three and six months ended June 30, 2011. During the three and six months ended June 30, 2010, we realized gains of $12.6 million and $13.5 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, 2011, and December 31, 2010.


			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value
	(In Thousands)
As of June 30, 2011:
Domestic equity	$	49,988	$	6,768	$	(272	)	$	56,484
International equity		24,225		2,654		—			26,879
Core bonds		21,457		279		—			21,736
High-yield bonds		9,071		344		—			9,415
Emerging market bonds		5,234		409		—			5,643
Combination debt/equity fund		7,601		64		—			7,665
Real estate securities		6,229		—		(2,933	)		3,296
Cash equivalents		3,429		—		—			3,429

Total	$	127,234	$	10,518	$	(3,205	)	$	134,547

As of December 31, 2010:
Domestic equity	$	58,592	$	4,972	$	(111	)	$	63,453
International equity		17,249		1,717		—			18,966
Core bonds		32,054		—		(148	)		31,906
High-yield bonds		9,086		486		—			9,572
Real estate securities		6,207		—		(3,158	)		3,049
Cash equivalents		44		—		—			44

Total	$	123,232	$	7,175	$	(3,417	)	$	126,990

The following table presents the fair value and 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, 2011, and December 31, 2010.


	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, 2011:
Domestic equity	$	2,257	$	(272	)	$	—	$	—		$	2,257	$	(272	)
Real estate securities		—		—			3,296		(2,933	)		3,296		(2,933	)

Total	$	2,257	$	(272	)	$	3,296	$	(2,933	)	$	5,553	$	(3,205	)

As of December 31, 2010:
Domestic equity	$	2,867	$	(111	)	$	—	$	—		$	2,867	$	(111	)
Core bonds		31,906		(148	)		—		—			31,906		(148	)
Real estate securities		—		—			3,049		(3,158	)		3,049		(3,158	)

Total	$	34,773	$	(259	)	$	3,049	$	(3,158	)	$	37,822	$	(3,417	)

5. RATE MATTERS AND REGULATION

KCC Proceedings

On May 27, 2011, the Kansas Corporation Commission (KCC) issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2010. The new prices were effective June 1, 2011, and are expected to increase our annual retail revenues by approximately $10.4 million.

We have a 50% interest in La Cygne Generating Station (La Cygne). Kansas City Power & Light Company (KCPL) is a 50% joint owner and the operator of the plant. On February 23, 2011, KCPL filed an application requesting that the KCC predetermine the ratemaking principles for and determine the appropriateness of approximately $1.2 billion of environmental upgrades proposed for La Cygne to comply with environmental regulations. We intervened in the proceeding. The KCC ruled in the May 27, 2011, order noted above that it would not approve recovery of our share of expenditures for environmental upgrades at La Cygne through the price adjustment approved in the order until the KCC’s investigation and analysis of the proposed upgrades is completed. In the KCPL proceeding, KCPL, KCC Staff and we agree that the La Cygne environmental upgrades should be completed as described in the application. Technical hearings on this matter concluded in mid July 2011 and the KCC is expected to issue a final order in late August 2011. If we are unable to collect the costs of La Cygne environmental upgrades through the environmental cost recovery rider (ECRR), we will experience an increase in the time between making these investments and having the costs reflected in the prices we charge our customers. This could also impact the amount we charge customers, and our plans to execute this project in part or whole could change. If the KCC were to rule against completing the environmental upgrades at La Cygne, we would not be able to comply with the aforementioned environmental regulations, which could ultimately result in shutting the plant down and requiring us to procure more expensive sources of power.

On April 11, 2011, the KCC issued an order allowing us to adjust our prices, subject to final KCC review, to include updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective April 14, 2011, and are expected to increase our annual retail revenues by $17.4 million. We expect the KCC to issue a final order on our request in the third quarter of 2011.

FERC Proceedings

Our transmission formula rate that includes projected 2011 transmission capital expenditures and operating costs became effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 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.

6. SHORT-TERM DEBT

Westar Energy has a $730.0 million revolving credit facility with a syndicate of banks that terminates on March 17, 2012. As of June 30, 2011, $471.0 million had been borrowed and an additional $15.6 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2010, $226.7 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility.

In February 2011, Westar Energy entered into a new revolving credit facility with a similar syndicate of banks for an additional $270.0 million. The commitments under this facility terminate on February 18, 2015. As of June 30, 2011, Westar Energy had neither borrowed monies nor issued letters of credit under this revolving credit facility.

7. TAXES

We recorded income tax expense of $19.6 million with an effective tax rate of 30% for the three months ended June 30, 2011, and income tax expense of $21.2 million with an effective income tax rate of 28% for the same period of 2010; and income tax expense of $33.1 million with an effective income tax rate of 30% for the six months ended June 30, 2011, and income tax expense of $35.0 million with an effective income tax rate of 29% for the same period of 2010. The increases in the effective income tax rates for the three and six months ended June 30, 2011, were due primarily to decreases in non-taxable income from corporate-owned life insurance in 2011 compared to 2010 and the settlement of the Internal Revenue Service’s examination of the 2009 tax year in the second quarter of 2011.

In 2010, we established a valuation allowance of $51.9 million against the unused state investment tax credits of $116.2 million. This valuation allowance was reversed during the second quarter of 2011 due to a state law change which extended the state investment tax credit carryforward period from 10 to 16 years.

At June 30, 2011, and December 31, 2010, our liability for unrecognized income tax benefits was $2.8 million and $1.9 million, respectively. The net increase in the liability for unrecognized income tax benefits was largely attributable to tax positions taken with respect to the capitalization of plant related expenditures. We do not expect any significant changes in this liability in the next 12 months.

As of June 30, 2011, and December 31, 2010, we had $0.4 million accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either June 30, 2011, or December 31, 2010.

As of June 30, 2011, and December 31, 2010, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

8. COMMITMENTS AND CONTINGENCIES

Federal Clean Air Act

We must comply with the Federal Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on emissions generated during our operations, including sulfur dioxide (SO₂), particulate matter, nitrogen oxides (NOx) and mercury. In addition, we must comply with the provisions of the Federal Clean Air Act Amendments of 1990 that require reductions in SO₂and NOx.

Emissions from our generating facilities, including particulate matter, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE), we are required to install and maintain controls to reduce emissions found to cause or contribute to regional haze.

Under the Federal Clean Air Act, the Environmental Protection Agency (EPA) sets National Ambient Air Quality Standards (NAAQS) for six criteria emissions considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO₂, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.

Environmental Projects

We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could change materially 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 the net production, reliability and availability of the 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 ECRR allows for the more timely inclusion in retail prices of the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our prices to recognize increased operating and maintenance costs, however, we must file a general rate case with the KCC. Moreover, as previously discussed, presently we are not allowed to use the ECRR to recover costs associated with proposed environmental upgrades at La Cygne while the KCC is reviewing the proposed upgrades. Upon the conclusion of that review, we expect to learn whether or not we can reinstate the ECRR for La Cygne.

Air Emissions

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which requires 27 states, including Kansas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions are required to begin January 1, 2012, with further reductions required beginning January 1, 2014. The EPA is issuing federal implementation plans for each state covered by CSAPR, but is allowing states to submit their own implementation plans starting as early as 2013.

There are a number of uncertainties relating to CSAPR, including how Kansas will implement the requirements. In addition, the implementation timeline for CSAPR is abbreviated in comparison to EPA precedent for regulations of similar magnitude. To comply with the rule on January 1, 2012, we expect that we must modify the way in which we use our power plants, purchase power or purchase emission allowances, as there is insufficient time to install equipment needed to reduce emissions to the levels required by the rule. We could incur substantial fines and penalties for noncompliance. We cannot yet determine the impact this new rule will have on our operations or consolidated financial results, but it could be material.

Greenhouse Gases

Under EPA regulations finalized in May 2010, known as the tailoring rule, the EPA began regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two Federal Clean Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement best available control technology (BACT). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these new regulations on our operations and consolidated financial results, but we believe the cost of compliance with new regulations could be material.

Renewable Energy Standard

In May 2009, Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. In years 2011 through 2015 net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. We have worked with third parties to develop approximately 300 MW of qualifying renewable generation facilities which, together with the use of renewable energy credits, we expect will allow us to meet the 2011 requirement. On December 14, 2010, we announced that we reached two separate agreements with third parties to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of renewable generation beginning in late 2012. The KCC approved the agreements and the associated cost recovery in an order dated May 9, 2011. We expect these agreements, along with our prior development of renewable generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in 2016.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and KDHE entered into a consent agreement governing all future work at these sites. Under 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), 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.

EPA Lawsuit

In March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement that we entered into with the parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at JEC violated certain requirements of the EPA’s New Source Review program, which 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. As part of the settlement agreement, in 2009 we recorded $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and a $3.0 million civil penalty. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In addition, we will install a selective catalytic reduction (SCR) on one of the three JEC coal units by the end of 2014. We estimate the cost of this to be approximately $240.0 million. This amount could change materially depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, we may have to install an SCR on another JEC 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 customers.

FERC Investigation

A non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008 remains pending. In May 2009, FERC staff alleged 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 first 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. In March 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 could potentially alter the manner in which we are permitted to buy and sell energy and use transmission service.

9. LEGAL PROCEEDINGS

In late 2002, one of our former executive officers resigned from his position and another executive officer was placed on administrative leave from his position. Following the completion of an investigation and the publication of a report prepared by a special committee of our board of directors, 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 and the publication of the report of the special committee. The arbitration was stayed in August 2004 pending final resolution of criminal charges filed against them in U.S. District Court in the District of Kansas. In August 2010, these criminal charges were dismissed and subsequently the stay of the arbitration was lifted. As of December 31, 2010, we had accrued liabilities of $80.6 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. In May 2011, we reached an agreement with Douglas T. Lake, one of the former executive officers, settling all contractual obligations and other claims. Pursuant to the agreement, we paid him approximately $21.0 million and we paid approximately $5.3 million for his legal fees and expenses. The accruals were reduced by the same amounts. As of June 30, 2011, we had accrued liabilities of $60.7 million for compensation not yet paid to David C. Wittig, the other former executive officer, and $3.1 million for his legal fees and expenses. In July 2011, we reached an agreement with Mr. Wittig settling all contractual obligations and other claims and providing for payments totaling approximately $36.0 million, the release of deferred stock for compensation shares and the payment of $3.1 million for his legal fees and expenses. The settlement with Mr. Wittig, and the reversal of approximately $22.0 million of previously accrued liabilities, will be recorded in our financial statements for the period ending September 30, 2011.

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 affect on our consolidated financial results. See Note 5, “Rate Matters and Regulation,” and Note 8, “Commitments and Contingencies,” for additional information.

10. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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,	2011			2010			2011			2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	4,021		$	3,445		$	450		$	330
Interest cost		9,960			9,854			1,704			1,754
Expected return on plan assets		(7,772	)		(9,595	)		(1,300	)		(1,239	)
Amortization of unrecognized:
Transition obligation, net		—			—			978			978
Prior service costs		303			697			723			533
Actuarial loss, net		5,915			4,347			97			59

Net periodic cost before regulatory adjustment		12,427			8,748			2,652			2,415
Regulatory adjustment		(5,641	)		(3,117	)		329			457

Net periodic cost	$	6,786		$	5,631		$	2,981		$	2,872


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2011			2010			2011			2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	8,038		$	6,963		$	902		$	763
Interest cost		19,915			19,696			3,397			3,542
Expected return on plan assets		(15,544	)		(19,192	)		(2,501	)		(2,599	)
Amortization of unrecognized:
Transition obligation, net		—			—			1,956			1,956
Prior service costs		606			1,364			1,262			1,077
Actuarial loss, net		11,830			8,592			351			160

Net periodic cost before regulatory adjustment		24,845			17,423			5,367			4,899
Regulatory adjustment		(11,267	)		(6,238	)		626			887

Net periodic cost	$	13,578		$	11,185		$	5,993		$	5,786

During the six months ended June 30, 2011 and 2010, we contributed $41.1 million and $16.8 million, respectively, to the Westar Energy pension trust.

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

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2011			2010			2011			2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	1,219		$	1,048		$	29		$	36
Interest cost		1,821			1,747			104			130
Expected return on plan assets		(1,428	)		(1,347	)		—			—
Amortization of unrecognized:
Transition obligation, net		13			14			14			14
Prior service costs		4			7			(8	)		—
Actuarial loss, net		798			712			38			69

Net periodic cost before regulatory adjustment		2,427			2,181			177			249
Regulatory adjustment		(663	)		(466	)		—			—

Net periodic cost	$	1,764		$	1,715		$	177		$	249


	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2011			2010			2011		2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	2,479		$	2,072		$	83	$	90
Interest cost		3,685			3,471			229		260
Expected return on plan assets		(2,953	)		(2,727	)		—		—
Amortization of unrecognized:
Transition obligation, net		26			28			29		28
Prior service costs		8			14			—		—
Actuarial loss, net		1,793			1,318			114		138

Net periodic cost before regulatory adjustment		5,038			4,176			455		516
Regulatory adjustment		(1,320	)		(788	)		—		—

Net periodic cost	$	3,718		$	3,388		$	455	$	516

During the six months ended June 30, 2011 and 2010, we funded $7.1 million and $1.8 million, respectively, of Wolf Creek’s pension plan contribution.

12. COMMON STOCK

On May 19, 2011, Westar Energy’s shareholders approved an amendment to its Restated Articles of Incorporation to increase the number of shares of common stock authorized to be issued from 150.0 million to 275.0 million.

During the six months ended June 30, 2011, Westar Energy delivered approximately 3.1 million shares of common stock as partial settlement of the forward sale agreement entered into with a bank in April 2010. In connection with these settlement transactions, Westar Energy received proceeds of $66.3 million. Assuming physical share settlement of the approximately 1.2 million remaining shares of common stock under this agreement at June 30, 2011, Westar Energy would have received aggregate proceeds of approximately $25.8 million based on an average forward price of $22.42 per share.

During the six months ended June 30, 2011, Westar Energy did not deliver any shares of common stock under the forward sale agreement entered into with a bank in November 2010. Assuming physical share settlement of the approximately 8.5 million shares of common stock under this agreement at June 30, 2011, Westar Energy would have received aggregate proceeds of approximately $200.4 million based on an average forward price of $23.63 per share.

13. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess 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. The trusts holding 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 are VIEs of which we are the primary beneficiary.

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

We have recorded the following assets and liabilities on our consolidated balance sheets as a result of consolidating the VIEs described above.


	As of June 30, 2011		As of December 31, 2010
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	339,253	$	345,037
Regulatory asset (a)		4,503		3,963

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,991	$	30,155
Accrued interest (b)		4,711		5,064
Long-term debt of variable interest entities, net		270,034		278,162



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

All of the liabilities noted in the table above relate to the VIEs’ ownership 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.

14. LEASES

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 seven years depending on the type of vehicle. Computer equipment has a lease term of four to five years.

On April 28, 2011, FERC issued an order approving a power supply agreement with the City of McPherson, Kansas. The agreement extends through May 2039. The terms of the agreement meet the criteria such that it is classified as a capital lease. Consequently, we recorded a $40.0 million capital lease.

Assets recorded under capital leases are listed below.


	June 30, 2011			December 31, 2010
	June 30, 2011			December 31, 2010
	(In Thousands)
Vehicles	$	14,177		$	12,504
Computer equipment and software		1,749			5,551
Power supply agreement		39,969			—
Accumulated amortization		(5,805	)		(8,744	)

Total capital leases	$	50,090		$	9,311

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, 2011			December 31, 2010
Total Capital Leases	June 30, 2011			December 31, 2010
	(In Thousands)
2011	$	4,181		$	2,110
2012		5,329			2,213
2013		5,097			1,908
2014		5,256			1,792
2015		4,336			1,391
Thereafter		71,046			1,157

		95,245			10,571
Amounts representing imputed interest		(45,155	)		(1,260	)

Present value of net minimum lease payments under capital leases		50,090			9,311
Less: current portion		2,807			1,797

Total long-term obligation under capital leases	$	47,283		$	7,514

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 2011 and our operating results for the three and six months ended June 30, 2011 and 2010. 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

Following is a summary of our net income and EPS.


	Three Months Ended June 30,							Six Months Ended June 30,
	2011		2010		Change			2011		2010		Change
	(Thousands of Dollars, Except per Share Amounts)							(Thousands of Dollars, Except per Share Amounts)
Net income attributable to common stock	$	43,887	$	53,069	$	(9,182	)	$	75,227	$	83,506	$	(8,279	)
Earnings per common share, basic		0.38		0.47		(0.09	)		0.66		0.75		(0.09	)

Net income attributable to common stock decreased for the three and six months ended June 30, 2011, compared to the same periods last year due primarily to higher operating expenses offset partially by higher total retail revenues. For additional information regarding these changes, see the discussion under “—Operating Results” below.

Current Trends

From time to time we update current trends discussed in our 2010 Form 10-K. The following is to be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Form 10-K.

Environmental Regulation

Environmental laws and regulations affecting power plants, which relate primarily to discharges into the air, air quality, discharges of effluents into water, the use of water, and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, continue to evolve and have become more stringent and costly over time. We have incurred and will continue to incur significant capital and other expenditures, and could potentially have to limit the use of some of our power plants, to comply with existing and new environmental laws and regulations. While certain of these costs are recoverable through the ECRR, and ultimately we expect that all such costs will be reflected in the prices we are allowed to charge customers, we cannot assure that all such costs will be recoverable in a timely manner.

Air Emissions

In July 2011, the EPA finalized CSAPR which requires 27 states, including Kansas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions are required to begin January 1, 2012, with further reductions required beginning January 1, 2014. The EPA is issuing federal implementation plans for each state covered by CSAPR, but is allowing states to submit their own implementation plans starting as early as 2013.

Additionally, also in July 2011, the EPA proposed to require six states, including Kansas, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this proposal would begin May 1, 2012. The EPA expects to finalize this proposal by October 31, 2011.

There are a number of uncertainties relating to CSAPR, including how Kansas will implement the requirements, and whether the proposed rule relating to ozone-season NOx reductions will be finalized. In addition, the implementation timeline for the finalized portion of CSAPR is abbreviated in comparison to EPA precedent for regulations of similar magnitude. To comply with the rule on January 1, 2012, we expect that we must modify the way in which we use our power plants, purchase power or purchase emission allowances, as there is insufficient time to install equipment needed to reduce emissions to the levels required by the rule. We could incur substantial fines and penalties for noncompliance. We cannot yet determine the impact this new rule will have on our operations or consolidated financial results, but it could be material.

In March 2011, the EPA proposed Mercury and Air Toxic Standards for power plants, which would replace the prior federal Clean Air Mercury Rule and would require significant reductions of mercury emissions as well as other air toxics from coal-fired power plants. A final rule is expected in November 2011. Without knowing what the rule will require, we cannot estimate the impact on us. However, our costs to comply with future mercury and air toxics emission requirements could have a material impact on our operations and consolidated financial results.

Greenhouse Gases

In December 2010, the EPA announced it will be proposing GHG New Source Performance Standard rules for power plants and refineries. The rules for power plants are expected to be proposed by September 30, 2011, and finalized in late May 2012. These rules would apply to new and existing facilities, including ours. Because these regulations have yet to be proposed, we cannot predict the impact they may have on our operations or consolidated financial results, but it could be material.

National Ambient Air Quality Standards

The EPA is currently in the process of revising the NAAQS for ozone. The EPA had announced it would issue these standards on July 29, 2011, but has postponed this date, noting only that the standards will be issued shortly. If these revisions result in more stringent standards, we could be required to place additional NOx pollution control measures on our facilities. Without knowing the new ozone standards, we cannot determine the impact they may have on our operations or consolidated financial results, but it could be material.

Regulation of Nuclear Generating Station

Additional regulation of Wolf Creek resulting from NRC oversight of the plant’s performance or from changing regulations generally, including those that could potentially result from events surrounding the Fukushima Daiichi nuclear power plant in Japan, or any event that might occur at any nuclear power plant anywhere in the world, may result in increased operating and capital expenditures. We cannot estimate the cost associated with such increases, but they could be material to our operations and consolidated financial results.

In March 2011, the NRC established a task force to conduct a review of U.S. nuclear power plant safety in the aftermath of an earthquake and tsunami that eventually resulted in station blackout and a very serious event at Japan’s Fukushima Daiichi nuclear power plant. The task force has provided a report and proposed improvements to the NRC which has the responsibility for making decisions regarding the task force recommendations. The timing and effects of any NRC action with respect to regulations, safety initiatives and licensing process cannot be determined at this time.

Coal Inventory and Delivery

Starting in late June and continuing through July, coal deliveries from the Powder River Basin region of Wyoming have been slower than normal due primarily to flooding occurring in the Midwest, which has shut down portions of the rail lines throughout the region. This has resulted in the rerouting of rail cars delivering coal to our power plants and has increased congestion on the rail lines.

We have implemented compensating measures based on delivery cycle times, our assumptions about future delivery cycle times, fuel usage, planned inventory levels, and projected water release levels from the U.S. Army Corps of Engineers. These measures include, but are not limited to, reducing coal consumption during lower priced periods, purchasing power and decreasing wholesale sales.

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 estimates and assumptions by management. The policies highlighted in our 2010 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, 2010, through June 30, 2011, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2010 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 to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.

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 sales based on prevailing market prices generally serve to offset our retail prices and the cost-based prices charged to certain wholesale customers.

Transmission: Reflects transmission revenues, including those based on tariffs 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 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, transmission availability and weather.

Three and Six Months Ended June 30, 2011, Compared to Three and Six Months Ended June 30, 2010

Below we discuss our operating results for the three and six months ended June 30, 2011, compared to the results for the three and six months ended June 30, 2010. 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,
	2011			2010			Change			% Change			2011			2010			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)												(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	157,120		$	150,094		$	7,026			4.7		$	310,028		$	294,837		$	15,191			5.2
Commercial		153,554			146,538			7,016			4.8			282,382			264,008			18,374			7.0
Industrial		91,245			83,110			8,135			9.8			170,441			152,150			18,291			12.0
Other retail		(2,440	)		(9,050	)		6,610			73.0			(5,455	)		(7,059	)		1,604			22.7

Total Retail Revenues		399,479			370,692			28,787			7.8			757,396			703,936			53,460			7.6
Wholesale		77,515			78,999			(1,484	)		(1.9	)		156,109			161,747			(5,638	)		(3.5	)
Transmission (a)		39,160			36,314			2,846			7.8			76,336			72,943			3,393			4.7
Other		8,738			9,176			(438	)		(4.8	)		16,770			16,385			385			2.3

Total Revenues		524,892			495,181			29,711			6.0			1,006,611			955,011			51,600			5.4

OPERATING EXPENSES:
Fuel and purchased power		152,973			137,116			15,857			11.6			287,157			270,916			16,241			6.0
Operating and maintenance		137,254			121,810			15,444			12.7			274,606			242,983			31,623			13.0
Depreciation and amortization		71,089			67,107			3,982			5.9			141,348			134,037			7,311			5.5
Selling, general and administrative		55,970			48,154			7,816			16.2			104,734			94,080			10,654			11.3

Total Operating Expenses		417,286			374,187			43,099			11.5			807,845			742,016			65,829			8.9

INCOME FROM OPERATIONS		107,606			120,994			(13,388	)		(11.1	)		198,766			212,995			(14,229	)		(6.7	)

OTHER INCOME (EXPENSE):
Investment earnings (losses)		1,374			(655	)		2,029			309.8			3,342			1,102			2,240			203.3
Other income		2,557			1,041			1,516			145.6			4,806			1,895			2,911			153.6
Other expense		(3,113	)		(2,403	)		(710	)		(29.5	)		(8,482	)		(6,897	)		(1,585	)		(23.0	)

Total Other Income (Expense)		818			(2,017	)		2,835			140.6			(334	)		(3,900	)		3,566			91.4

Interest expense		43,300			43,289			11			(b	)		86,838			87,905			(1,067	)		(1.2	)

INCOME BEFORE INCOME TAXES		65,124			75,688			(10,564	)		(14.0	)		111,594			121,190			(9,596	)		(7.9	)
Income tax expense		19,599			21,158			(1,559	)		(7.4	)		33,112			34,979			(1,867	)		(5.3	)

NET INCOME		45,525			54,530			(9,005	)		(16.5	)		78,482			86,211			(7,729	)		(9.0	)
Less: Net income attributable to noncontrolling interests		1,396			1,219			177			14.5			2,770			2,220			550			24.8

NET INCOME ATTRIBUTABLE TO WESTAR ENERGY		44,129			53,311			(9,182	)		(17.2	)		75,712			83,991			(8,279	)		(9.9	)
Preferred dividends		242			242			—			—			485			485			—			—

NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	43,887		$	53,069		$	(9,182	)		(17.3	)	$	75,227		$	83,506		$	(8,279	)		(9.9	)

BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY	$	0.38		$	0.47		$	(0.09	)		(19.1	)	$	0.66		$	0.75		$	(0.09	)		(12.0	)

(a)

Transmission: Reflects revenue from an SPP network transmission tariff. For the three and six months ended June 30, 2011, our SPP network transmission costs were $32.7 million and $64.7 million, respectively. These amounts, less $4.1 million and $8.3 million, respectively, were returned to us as revenue. For the three and six months ended June 30, 2010, our SPP network transmission costs were $28.9 million and $56.1 million, respectively. These amounts, less $4.6 million and $7.7 million, respectively, were returned to us as revenue.

(b)	Change less than 0.1%.

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. 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 minimal impact on net income. For this reason, we believe gross margin 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, 2011 and 2010.


	Three Months Ended June 30,												Six Months Ended June 30,
	2011			2010			Change			% Change			2011			2010			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)												(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	157,120		$	150,094		$	7,026			4.7		$	310,028		$	294,837		$	15,191			5.2
Commercial		153,554			146,538			7,016			4.8			282,382			264,008			18,374			7.0
Industrial		91,245			83,110			8,135			9.8			170,441			152,150			18,291			12.0
Other retail		(2,440	)		(9,050	)		6,610			73.0			(5,455	)		(7,059	)		1,604			22.7

Total Retail Revenues		399,479			370,692			28,787			7.8			757,396			703,936			53,460			7.6
Wholesale		77,515			78,999			(1,484	)		(1.9	)		156,109			161,747			(5,638	)		(3.5	)
Transmission		39,160			36,314			2,846			7.8			76,336			72,943			3,393			4.7
Other		8,738			9,176			(438	)		(4.8	)		16,770			16,385			385			2.3

Total Revenues		524,892			495,181			29,711			6.0			1,006,611			955,011			51,600			5.4
Less: Fuel and purchased power expense		152,973			137,116			15,857			11.6			287,157			270,916			16,241			6.0
SPP network transmission costs		32,685			28,910			3,775			13.1			64,736			56,064			8,672			15.5

Gross Margin	$	339,234		$	329,155		$	10,079			3.1		$	654,718		$	628,031		$	26,687			4.2

The following table reflects changes in electricity sales for the three and six months ended June 30, 2011 and 2010. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.


	Three Months Ended June 30,										Six Months Ended June 30,
	2011		2010		Change			% Change			2011		2010		Change			% Change
	(Thousands of MWh)										(Thousands of MWh)
ELECTRICITY SALES:
Residential		1,549		1,530		19			1.2			3,207		3,212		(5	)		(0.2	)
Commercial		1,890		1,908		(18	)		(0.9	)		3,594		3,575		19			0.5
Industrial		1,438		1,405		33			2.3			2,776		2,682		94			3.5
Other retail		22		23		(1	)		(4.3	)		43		44		(1	)		(2.3	)

Total retail		4,899		4,866		33			0.7			9,620		9,513		107			1.1
Wholesale		1,776		2,201		(425	)		(19.3	)		3,687		4,500		(813	)		(18.1	)

Total		6,675		7,067		(392	)		(5.5	)		13,307		14,013		(706	)		(5.0	)

Gross margin increased for the three and six months ended June 30, 2011, compared to the same periods last year due primarily to higher total retail revenues. For the three and six months ended June 30, 2011, 91% and 85%, respectively, of the increases in total retail revenues were due to higher prices, and 9% and 15%, respectively, were attributable to higher electricity sales. Higher retail electricity sales were principally the result of increased industrial electricity sales. Although economic conditions generally have not recovered to levels experienced prior to the economic downturn, we believe improving economic conditions are why some of our industrial customers experienced increased production, which resulted in more electricity sales to them.

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, 2011 and 2010.


	Three Months Ended June 30,										Six Months Ended June 30,
	2011		2010		Change			% Change			2011		2010		Change			% Change
	(Dollars In Thousands)										(Dollars In Thousands)
Gross margin	$	339,234	$	329,155	$	10,079			3.1		$	654,718	$	628,031	$	26,687			4.2
Add: SPP network transmission costs		32,685		28,910		3,775			13.1			64,736		56,064		8,672			15.5
Less: Operating and maintenance expense		137,254		121,810		15,444			12.7			274,606		242,983		31,623			13.0
Depreciation and amortization expense		71,089		67,107		3,982			5.9			141,348		134,037		7,311			5.5
Selling, general and administrative expense		55,970		48,154		7,816			16.2			104,734		94,080		10,654			11.3

Income from operations	$	107,606	$	120,994	$	(13,388	)		(11.1	)	$	198,766	$	212,995	$	(14,229	)		(6.7	)

Operating Expenses and Other Income and Expense Items


	Three Months Ended June 30,								Six Months Ended June 30,
	2011		2010		Change		% Change		2011		2010		Change		% Change
	(Dollars In Thousands)
Operating and maintenance expense	$	137,254	$	121,810	$	15,444		12.7	$	274,606	$	242,983	$	31,623		13.0

Operating and maintenance expense increased for the three and six months ended June 30, 2011, compared to the same periods last year due primarily to higher SPP network transmission costs of $3.8 million and $8.7 million, respectively, which were offset by higher SPP network transmission revenues of $4.3 million and $8.0 million, respectively; higher costs at Wolf Creek of $4.1 million and $7.4 million, respectively; our having recorded in June 2010 a $5.0 million reduction in our maximum liability for environmental remediation costs associated with assets we divested many years ago; and increases of $1.6 million and $2.4 million, respectively, in property taxes, which were offset in retail revenues. The increases in operating and maintenance costs at Wolf Creek were related principally to higher regulatory compliance costs and increases of $2.1 million in the amortization of deferred refueling and maintenance outage costs. We expect the higher level of costs at Wolf Creek to continue. Contributing to the increase for the six months ended June 30, 2011, were higher maintenance costs of $2.5 million for our electrical distribution system attributable principally to additional tree trimming and other line clearance activities.


	Three Months Ended June 30,								Six Months Ended June 30,
	2011		2010		Change		% Change		2011		2010		Change		% Change
	(Dollars In Thousands)
Depreciation and amortization expense	$	71,089	$	67,107	$	3,982		5.9	$	141,348	$	134,037	$	7,311		5.5

Depreciation and amortization expense increased for the three and six months ended June 30, 2011, compared to the same periods last year as a result of our having recorded additional depreciation expense associated primarily with the addition of transmission facilities and air quality controls at our power plants.


	Three Months Ended June 30,								Six Months Ended June 30,
	2011		2010		Change		% Change		2011		2010		Change		% Change
	(Dollars In Thousands)
Selling, general and administrative expense	$	55,970	$	48,154	$	7,816		16.2	$	104,734	$	94,080	$	10,654		11.3

Selling, general and administrative expense increased for the three and six months ended June 30, 2011, compared to the same periods last year due primarily to higher legal fees of $4.0 million and $5.7 million, respectively, related principally to the arbitration proceedings discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.” Contributing to the increases was the amortization of $0.9 million and $1.8 million, respectively, of previously deferred amounts associated with various energy efficiency programs, which was offset in retail revenues.


	Three Months Ended June 30,									Six Months Ended June 30,
	2011		2010			Change		% Change		2011		2010		Change		% Change
	(Dollars In Thousands)
Investment earnings (losses)	$	1,374	$	(655	)	$	2,029		309.8	$	3,342	$	1,102	$	2,240		203.3

Investment earnings increased for the three and six months ended June 30, 2011, compared to the same periods last year due primarily to improved performance of investments held in a trust to fund retirement benefits. For the three and six months ended June 30, 2011, we recorded gains on these investments of $0.6 million and $2.5 million, respectively. We recorded losses on these investments of $2.6 million and $1.1 million, respectively, during the same periods of 2010.


	Three Months Ended June 30,								Six Months Ended June 30,
	2011		2010		Change		% Change		2011		2010		Change		% Change
	(Dollars In Thousands)
Other income	$	2,557	$	1,041	$	1,516		145.6	$	4,806	$	1,895	$	2,911		153.6

Other income increased for the three and six months ended June 30, 2011, compared to the same periods last year due principally to increases in equity AFUDC of $1.0 million and $2.3 million, respectively. The increases in equity AFUDC were attributable to increased construction activity.


	Three Months Ended June 30,										Six Months Ended June 30,
	2011		2010		Change			% Change			2011		2010		Change			% Change
	(Dollars In Thousands)
Income tax expense	$	19,599	$	21,158	$	(1,559	)		(7.4	)	$	33,112	$	34,979	$	(1,867	)		(5.3	)

Income tax expense decreased for the three and six months ended June 30, 2011, compared to the same periods last year due principally to lower income before income taxes.

FINANCIAL CONDITION

Below we discuss significant balance sheet changes as of June 30, 2011, compared to December 31, 2010.

Inventory and supplies increased $17.1 million due primarily to a 10% increase in delivered coal costs and an 11% increase in coal volumes. The increase in delivered coal costs was due primarily to escalation provisions in a long-term transportation contract at La Cygne. The increased volumes were due principally to a spring outage.

Current deferred tax assets decreased $21.6 million due primarily to the Wolf Creek refueling and maintenance outage and to the payment of non-union, non-executive, at-risk employee compensation related to 2010 compensation metrics. This compensation is payable only in the event we meet pre-established operating and financial objectives. Further contributing to the decrease was the settlement with a former executive officer as discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.”

Regulatory assets, net of regulatory liabilities, increased $12.6 million to $709.6 million at June 30, 2011, from $697.0 million at December 31, 2010. Regulatory assets increased $21.6 million due primarily to a $26.9 million increase in net amounts deferred for the Wolf Creek outage and the deferral of $13.1 million of fuel expense. Increases were partially offset by a $9.2 million decrease in deferred employee benefit costs and the amortization of $7.7 million for previously deferred storm costs. Regulatory liabilities increased $9.0 million due primarily to a $7.6 million increase in the fair value of our NDT assets and a $5.4 million increase in our obligation related to other post-retirement benefit costs. Increases were partially offset by a $4.9 million decrease in our obligation to refund customers for the overcollection of property taxes.

Property, plant and equipment, net, increased $209.7 million due to additions of $194.1 million at our power plants due primarily to additional air quality controls.

Long-term debt of variable interest entities, including current maturities, decreased $11.3 million due primarily to our having made payments for our 8% leasehold interest in JEC and a railcar lease accounted for as VIEs.

Short-term debt increased $244.3 million due principally to increased borrowings under Westar Energy’s revolving credit facility. We used borrowings under the revolving credit facility to fund our capital and on-going operating needs.

Other current liabilities decreased $22.2 million due primarily to the payment of non-union, non-executive, at-risk employee compensation related to 2010 compensation metrics and our having reached a settlement agreement with a former officer as discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.”

The net deferred income taxes decreased $48.0 million due primarily to the reversal of a valuation allowance of $51.9 million. The valuation allowance relates to state tax credit carryforwards that are now more likely than not to be realized due to a state law change which extended the state tax credit carryforward period from 10 to 16 years.

Unamortized investment tax credits increased $53.9 million due primarily to reversing $51.9 million of valuation allowances on state investment tax credits as discussed in the prior paragraph.

Accrued employee benefits decreased $46.0 million due principally to our having made payments of $41.1 million to our pension trust.

Other long-term liabilities increased $23.0 million due primarily to the addition of a capital lease. See Note 14 of the Notes to Condensed Consolidated Financial Statements, “Leases,” for further information.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy’s revolving credit facilities and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and borrowings under the revolving credit facilities. To meet the cash requirements for our capital investments, we expect to use internally generated cash, borrowings under the revolving credit facilities and the issuance of debt and equity securities in the capital markets. We also use proceeds from the issuance of securities to repay borrowings under the revolving credit facilities, with such borrowed amounts principally related to investments in capital equipment, and for working capital and general corporate purposes. The aforementioned sources and uses of cash are similar to our historical activities. 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

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million, respectively. As of July 26, 2011, $485.0 million had been borrowed and an additional $18.2 million of letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date. We anticipate refinancing the $730.0 million revolving credit facility later this year.

Common Stock

Cash Flows from Operating Activities

Operating activities provided $71.4 million of cash in the six months ended June 30, 2011, compared with cash provided of $238.8 million during the same period of 2010. The decrease was due primarily to our having paid $69.6 million more for fuel and purchased power, which was the result principally of our having purchased significantly more power during planned maintenance outages at some of our power plants, $32.6 million more for the planned Wolf Creek refueling and maintenance outage, $28.7 million more for pension and post-retirement benefit plan contributions, and our having paid $1.1 million for income taxes in 2011 compared to receiving income tax refunds of $44.3 million in 2010 related to the utilization of net operating loss carryforwards. For the six months ended June 30, 2011, we also paid a former executive officer approximately $21.0 million in compensation and paid approximately $5.3 million for his legal fees and expenses pursuant to a settlement agreement as discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements, “Legal Proceedings.” Partially offsetting these decreases was our having received approximately $49.1 million more in customer receipts. Although we recover fuel and purchased power costs through the RECA, there is a delay between when we pay for fuel and purchased power and when we receive cash from our customers.

Cash Flows used in Investing Activities

Investing activities used $359.2 million of cash in the six months ended June 30, 2011, compared to $255.8 million during the same period of 2010. We spent $345.6 million in the six months ended June 30, 2011, and $237.6 million in the same period of 2010 on additions to property, plant and equipment.

Cash Flows from Financing Activities

Financing activities provided $292.1 million of cash in the six months ended June 30, 2011, compared to $16.4 million during the same period of 2010. The increase was due primarily to our having borrowed $242.1 million under Westar Energy’s revolving credit facility during the six months ended June 30, 2011, compared to our having repaid $2.0 million of borrowings during the same period of 2010. We also received $41.9 million more in proceeds from the issuance of common stock. We used borrowings under the revolving credit facility to fund our capital and on-going operating needs while the proceeds from the issuance of common stock were used to repay such borrowings as well as for working capital and general corporate purposes.

Debt Covenants

We remain in compliance with the debt covenants described in our 2010 Form 10-K.

Credit Ratings

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

In general, less favorable credit ratings make borrowing more difficult and costly. Under Westar Energy’s revolving credit facilities our cost of borrowing is determined in part by credit ratings. However, Westar Energy’s ability to borrow under the revolving credit facilities 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.

On May 31, 2011, Fitch upgraded its credit ratings for Westar Energy and KGE first mortgage bonds/senior secured debt to A- from BBB+. Fitch also upgraded its credit rating for Westar Energy unsecured debt to BBB+ from BBB and changed its outlook for the ratings from positive to stable. As of July 26, 2011, our ratings with the agencies are as shown in the following table.


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

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, 2011, and December 31, 2010, was $6.6 million and $1.6 million, respectively, for which we had posted $1.6 million of collateral, including independent amounts, as of June 30, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2011, and December 31, 2010, we would have been required to provide to our counterparties $2.0 million and $1.6 million, respectively, 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, 2011, we contributed $41.1 million to the Westar Energy pension trust and funded $7.1 million of Wolf Creek’s pension plan contribution.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2010, through June 30, 2011, our off-balance sheet arrangements did not change materially. For additional information, see our 2010 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2010, through June 30, 2011, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2010 Form 10-K.

OTHER INFORMATION

Changes in Prices

KCC Proceedings

On May 31, 2011, we gave notice to the KCC that we plan to file a general rate case no later than August 29, 2011.

On May 27, 2011, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2010. The new prices were effective June 1, 2011, and are expected to increase our annual retail revenues by approximately $10.4 million.

We have a 50% interest in La Cygne. KCPL is a 50% joint owner and the operator of the plant. On February 23, 2011, KCPL filed an application requesting that the KCC predetermine the ratemaking principles for and determine the appropriateness of approximately $1.2 billion of environmental upgrades proposed for La Cygne to comply with environmental regulations. We intervened in the proceeding. The KCC ruled in the May 27, 2011, order noted above that it would not approve recovery of our share of expenditures for environmental upgrades at La Cygne through the price adjustment approved in the order until the KCC’s investigation and analysis of the proposed upgrades is completed. In the KCPL proceeding, KCPL, KCC Staff and we agree that the La Cygne environmental upgrades should be completed as described in the application. Technical hearings on this matter concluded in mid July 2011 and the KCC is expected to issue a final order in late August 2011. If we are unable to collect the costs of La Cygne environmental upgrades through the ECRR, we will experience an increase in the time between making these investments and having the costs reflected in the prices we charge our customers. This could also impact the amount we charge customers, and our plans to execute this project in part or whole could change. If the KCC were to rule against completing the environmental upgrades at La Cygne, we would not be able to comply with the aforementioned environmental regulations, which could ultimately result in shutting the plant down and requiring us to procure more expensive sources of power.

FERC Proceedings

Employees

As of July 26, 2011, we had 2,416 employees, 1,315 of which were covered under a contract with Locals 304 and 1523 of the International Brotherhood of Electrical Workers. The initial term of this contract expired June 30, 2011; however, provisions of the contract cause it to remain in force on a year-to-year basis unless either party provides a notice of termination. With neither party having provided such notice, the contract remains in effect until at least June 30, 2012. We are currently in negotiations to extend the contract.

Fair Value of Energy Marketing Contracts

The following table shows the fair value of energy marketing contracts outstanding as of June 30, 2011.


	Fair Value of Contracts
	(In Thousands)
Net fair value of contracts outstanding as of December 31, 2010 (a)	$	12,797
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period		(1,349	)
Changes in fair value of contracts outstanding at the beginning and end of the period		(797	)
Fair value of new contracts entered into during the period		364

Fair value of contracts outstanding as of June 30, 2011 (b)	$	11,015

(a)	Approximately $7.8 million of the fair value of energy marketing contracts was recognized as a regulatory liability.

(b)	Approximately $6.6 million of the fair value of energy marketing contracts was recognized as a regulatory liability.

The sources of the fair values of the financial instruments related to these contracts and the maturity periods of the contracts as of June 30, 2011, 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
	(Dollars In Thousands)
Prices provided by other external sources (swaps and forwards)	$	11,670		$	2,828	$	7,679		$	1,163		$	—
Prices based on option pricing models (options and other) (a)		(655	)		52		(530	)		(177	)		—

Total fair value of contracts outstanding	$	11,015		$	2,880	$	7,149		$	986		$	—

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including changes in commodity prices, counterparty credit, interest rates, and debt and equity instrument values. From December 31, 2010, to June 30, 2011, no significant changes occurred in our market risk exposure. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2010 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, 2011, 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 5, 8 and 9 of the Notes to Condensed Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 1A.

RISK FACTORS

Our costs of compliance with environmental laws are significant, and the future cost of compliance with environmental laws could adversely affect our consolidated financial results.

We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, requires us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air quality control equipment and purchases of air emission allowances and/or offsets.

Costs of compliance with environmental regulations or fines or penalties resulting from non-compliance, if not recovered in our prices, could adversely affect our consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty due to our inability to predict the requirements and timing of implementation of environmental rules or regulations.

There were no other material changes in our risk factors from December 31, 2010, through June 30, 2011. For additional information, see our 2010 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.

REMOVED AND RESERVED

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS


10(a)		Amendment to Long-Term Incentive and Share Award Plan (filed as Exhibit 10 to the Form 8-K filed on May 6, 2011)

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, 2011

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, 2011

32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2011 (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 4, 2011	By:	/s/ Anthony D. Somma
			Anthony D. Somma Senior Vice President, Chief Financial Officer and Treasurer

Certification of Principal Executive Officer pursuant to Section 302

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:

I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2011, of Westar Energy, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	August 4, 2011	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle Director, President and Chief Executive Officer Westar Energy, Inc. (Principal Executive Officer)

Certification of Principal Financial Officer pursuant to Section 302

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:

I have reviewed this quarterly report on Form 10-Q for the period ended June 30, 2011, of Westar Energy, Inc.;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	August 4, 2011	By:	/s/ Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer Westar Energy, Inc. (Principal Accounting Officer)

Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Westar Energy, Inc. (the Company) on Form 10-Q for the quarter ended June 30, 2011 (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:

August 4, 2011

By:

/s/ Mark A. Ruelle

Mark A. Ruelle

Director, President and Chief Executive Officer

Date:

August 4, 2011

By:

/s/ Anthony D. Somma

Senior Vice President, Chief

Financial Officer and Treasurer