Edgar Filing: WESTAR ENERGY INC /KS

WR-6.30.2012-10Q

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, 2012



[ ]	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		126,315,391 shares
(Class)		(Outstanding at July 31, 2012)

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TABLE OF CONTENTS




PART I. Financial Information		Page
Item 1.	Condensed Consolidated Financial Statements (Unaudited)
	Consolidated Balance Sheets	6
	Consolidated Statements of Income	7
	Consolidated Statements of Cash Flows	9
	Consolidated Statements of Changes in Equity	10
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49

PART II. Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	50
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	50
Signature		51

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GLOSSARY OF TERMS

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



Abbreviation or Acronym		Definition
AFUDC		Allowance for funds used during construction
BACT		Best Available Control Technology
CAMR		Clean Air Mercury Rule
CCB		Coal combustion byproduct
CO		Carbon monoxide
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
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
MATS		Mercury and Air Toxics Standards
MMBtu		Millions of Btu
Moody’s		Moody’s Investors Service
MW		Megawatt(s)
MWh		Megawatt hour(s)
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NOx		Nitrogen oxides
ONEOK		ONEOK, Inc.
OTC		Over-the-counter
PM		Particulate matter
PSD		Prevention of Significant Deterioration program
RCRA		Resource Conservation and Recovery Act
RSU		Restricted share unit
S&P		Standard & Poor’s Ratings Services
SCR		Selective catalytic reduction equipment
SO2		Sulfur dioxide
SPP		Southwest Power Pool
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

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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 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 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,


-	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,

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-	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, 2011 (2011 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 2011 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 2011 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.

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PART I. FINANCIAL INFORMATION

ITEM I. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values) (Unaudited)



	As of		As of
	June 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,654	$	3,539
Restricted cash	22,567		—
Accounts receivable, net of allowance for doubtful accounts of $4,919 and $7,384, respectively	277,488		226,428
Fuel inventory and supplies	256,316		229,118
Energy marketing contracts	5,981		8,180
Taxes receivable	—		5,334
Deferred tax assets	—		394
Prepaid expenses	14,883		13,078
Regulatory assets	111,374		123,818
Other	21,022		23,696
Total Current Assets	716,285		633,585
PROPERTY, PLANT AND EQUIPMENT, NET	6,724,590		6,411,922
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	327,734		333,494
OTHER ASSETS:
Regulatory assets	909,488		922,272
Nuclear decommissioning trust	140,741		130,270
Other	223,983		251,308
Total Other Assets	1,274,212		1,303,850
TOTAL ASSETS	$	9,042,821	$	8,682,851
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	45,853	$	28,114
Short-term debt	348,407		286,300
Accounts payable	151,227		187,428
Accrued taxes	63,102		52,451
Energy marketing contracts	4,414		6,353
Accrued interest	50,440		77,437
Regulatory liabilities	44,592		40,857
Other	142,759		148,347
Total Current Liabilities	850,794		827,287
LONG-TERM LIABILITIES:
Long-term debt, net	2,818,966		2,491,109
Long-term debt of variable interest entities, net	223,506		249,283
Deferred income taxes	1,138,708		1,110,463
Unamortized investment tax credits	161,389		164,175
Regulatory liabilities	292,535		230,530
Accrued employee benefits	546,793		592,617
Asset retirement obligations	146,541		142,508
Other	69,475		74,138
Total Long-Term Liabilities	5,397,913		5,054,823
COMMITMENTS AND CONTINGENCIES (See Notes 8 and 9)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding zero shares and 214,363 shares, respectively	—		21,436
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 126,223,848 shares and 125,698,396 shares, respectively	631,119		628,492
Paid-in capital	1,646,991		1,639,503
Retained earnings	505,720		501,216
Total Westar Energy, Inc. Shareholders’ Equity	2,783,830		2,790,647
Noncontrolling Interests	10,284		10,094
Total Equity	2,794,114		2,800,741
TOTAL LIABILITIES AND EQUITY	$	9,042,821	$	8,682,851

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Three Months Ended June 30,
	2012			2011
REVENUES	$	566,262		$	524,892
OPERATING EXPENSES:
Fuel and purchased power	147,680			152,973
Operating and maintenance	156,470			137,254
Depreciation and amortization	66,299			71,089
Selling, general and administrative	62,711			55,970
Total Operating Expenses	433,160			417,286
INCOME FROM OPERATIONS	133,102			107,606
OTHER INCOME (EXPENSE):
Investment (losses) earnings	(598		)	1,374
Other income	7,537			2,557
Other expense	(2,416		)	(3,113		)
Total Other Income	4,523			818
Interest expense	44,823			43,300
INCOME BEFORE INCOME TAXES	92,802			65,124
Income tax expense	28,340			19,599
NET INCOME	64,462			45,525
Less: Net income attributable to noncontrolling interests	1,728			1,396
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	62,734			44,129
Preferred dividends	1,373			242
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	61,361		$	43,887
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC. (See Note 2)	$	0.48		$	0.38
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING	126,637,067			114,908,123
DIVIDENDS DECLARED PER COMMON SHARE	$	0.33		$	0.32

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)



	Six Months Ended June 30,
	2012			2011
REVENUES	$	1,041,940		$	1,006,611
OPERATING EXPENSES:
Fuel and purchased power	275,334			287,157
Operating and maintenance	312,514			274,606
Depreciation and amortization	139,579			141,348
Selling, general and administrative	110,046			104,734
Total Operating Expenses	837,473			807,845
INCOME FROM OPERATIONS	204,467			198,766
OTHER INCOME (EXPENSE):
Investment earnings	3,727			3,342
Other income	21,127			4,806
Other expense	(7,969		)	(8,482		)
Total Other Income (Expense)	16,885			(334		)
Interest expense	86,869			86,838
INCOME BEFORE INCOME TAXES	134,483			111,594
Income tax expense	40,783			33,112
NET INCOME	93,700			78,482
Less: Net income attributable to noncontrolling interests	3,442			2,770
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY	90,258			75,712
Preferred dividends	1,616			485
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	88,642		$	75,227
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2):
Basic earnings per common share	$	0.70		$	0.66
Diluted earnings per common share	$	0.70		$	0.65
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING	126,566,071			114,396,909
DIVIDENDS DECLARED PER COMMON SHARE	$	0.66		$	0.64

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	93,700		$	78,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	139,579			141,348
Amortization of nuclear fuel	9,026			5,913
Amortization of deferred regulatory gain from sale leaseback	(2,748		)	(2,748		)
Amortization of corporate-owned life insurance	10,921			12,041
Non-cash compensation	3,738			4,889
Net changes in energy marketing assets and liabilities	(425		)	417
Net deferred income taxes and credits	33,586			26,645
Stock-based compensation excess tax benefits	(1,498		)	(727		)
Allowance for equity funds used during construction	(6,778		)	(3,421		)
Changes in working capital items:
Accounts receivable	(51,055		)	(44,249		)
Fuel inventory and supplies	(26,830		)	(16,682		)
Prepaid expenses and other	15,255			(28,608		)
Accounts payable	(8,741		)	17,013
Accrued taxes	16,276			10,173
Other current liabilities	(59,356		)	(85,444		)
Changes in other assets	(40,100		)	(13,673		)
Changes in other liabilities	(21,371		)	(29,922		)
Cash Flows from Operating Activities	103,179			71,447
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(417,617		)	(345,550		)
Purchase of securities within trusts	(16,817		)	(34,560		)
Sale of securities within trusts	18,040			33,821
Proceeds from trust	1,183			—
Investment in corporate-owned life insurance	(18,167		)	(18,845		)
Proceeds from investment in corporate-owned life insurance	16,330			744
Proceeds from federal grant	3,289			3,746
Investment in affiliated company	(4,505		)	(909		)
Investment in non-utility investments	(302		)	—
Other investing activities	(1,224		)	2,354
Cash Flows used in Investing Activities	(419,790		)	(359,199		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	62,107			242,091
Proceeds from long-term debt	541,504			—
Retirements of long-term debt	(220,563		)	(191		)
Retirements of long-term debt of variable interest entities	(7,736		)	(10,903		)
Repayment of capital leases	(1,287		)	(931		)
Borrowings against cash surrender value of corporate-owned life insurance	63,287			64,875
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(18,252		)	(3,020		)
Stock-based compensation excess tax benefits	1,498			727
Preferred stock redemption	(22,567		)	—
Issuance of common stock	3,697			69,220
Distributions to shareholders of noncontrolling interests	(3,252		)	(1,916		)
Cash dividends paid	(78,710		)	(67,846		)
Cash Flows from Financing Activities	319,726			292,106
NET INCREASE IN CASH AND CASH EQUIVALENTS	3,115			4,354
CASH AND CASH EQUIVALENTS:
Beginning of period	3,539			928
End of period	$	6,654		$	5,282

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

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)

(Unaudited)



	Westar Energy Shareholders
	Cumulative preferred stock shares		Cumulative preferred stock			Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2010	214,363		$	21,436		112,128,068	$	560,640	$	1,398,580		$	423,647		$	6,070		$	2,410,373
Net income	—		—			—	—		—			75,712			2,770			78,482
Issuance of stock	—		—			3,589,277	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 as of June 30, 2011	214,363		$	21,436		115,717,345	$	578,586	$	1,458,490		$	425,273		$	6,924		$	2,490,709

Balance as of December 31, 2011	214,363		$	21,436		125,698,396	$	628,492	$	1,639,503		$	501,216		$	10,094		$	2,800,741
Net income	—		—			—	—		—			90,258			3,442			93,700
Issuance of stock	—		—			525,452	2,627		12,274			—			—			14,901
Stock redemption	(214,363	)	(21,436		)	—	—		—			—			—			(21,436		)
Preferred dividends	—		—			—	—		—			(1,616		)	—			(1,616		)
Dividends on common stock	—		—			—	—		—			(84,138		)	—			(84,138		)
Amortization of restricted stock	—		—			—	—		3,004			—			—			3,004
Stock compensation and tax benefit	—		—			—	—		(7,790		)	—			—			(7,790		)
Distributions to shareholders of noncontrolling interests	—		—			—	—		—			—			(3,252		)	(3,252		)
Balance as of June 30, 2012	—		$	—		126,223,848	$	631,119	$	1,646,991		$	505,720		$	10,284		$	2,794,114

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

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WESTAR ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 691,000 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 reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. 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 2011 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 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 billed to customers, income taxes, pension and 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, 2012, are not necessarily indicative of the results to be expected for the full year.

Restricted Cash

Pursuant to Westar Energy's Articles of Incorporation, Westar Energy deposited cash in a separate account to effect the redemption of all of Westar Energy's preferred stock. See Note 12, "Common and Preferred Stock," for additional information regarding the preferred stock redemption.

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Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.



	As of		As of
	June 30, 2012		December 31, 2011
	(In Thousands)
Fuel inventory	$	115,615	$	86,408
Supplies	140,701		142,710
Total	$	256,316	$	229,118

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,
	2012			2011			2012			2011
	(Dollars In Thousands)
Borrowed funds	$	2,440		$	1,562		$	5,959		$	3,062
Equity funds	2,838			1,669			6,778			3,421
Total	$	5,278		$	3,231		$	12,737		$	6,483
Average AFUDC Rates	4.9		%	4.2		%	5.4		%	4.4		%

Earnings Per Share

We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on 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 number of common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements, RSUs with forfeitable rights to dividend equivalents and stock options. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	64,462	$	45,525	$	93,700	$	78,482
Less: Net income attributable to noncontrolling interests	1,728		1,396		3,442		2,770
Net income attributable to Westar Energy, Inc.	62,734		44,129		90,258		75,712
Less: Preferred dividends	1,373		242		1,616		485
Net income allocated to RSUs	182		19		265		138
Net income allocated to common stock	$	61,179	$	43,868	$	88,377	$	75,089

Weighted average equivalent common shares outstanding – basic	126,637,067		114,908,123		126,566,071		114,396,909
Effect of dilutive securities:
RSUs	190,422		182,384		155,340		169,165
Forward sale agreements	49,047		1,846,084		23,128		1,779,107
Weighted average equivalent common shares outstanding – diluted (a)	126,876,536		116,936,591		126,744,539		116,345,181

Earnings per common share, basic	$	0.48	$	0.38	$	0.70	$	0.66
Earnings per common share, diluted	$	0.48	$	0.38	$	0.70	$	0.65

_______________


(a)	We had no antidilutive shares for the three and six months ended June 30, 2012 and 2011.

Supplemental Cash Flow Information



	Six Months Ended June 30,
	2012			2011
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	68,939		$	72,225
Interest on financing activities of VIEs	8,281			9,335
Income taxes, net of refunds	(4,635		)	1,113
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	37,736			73,989
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans	4,920			7,909
Assets acquired through capital leases	1,543			41,901

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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 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 and long-term electricity supply contracts. Level 3 also includes investments in private equity and real estate securities, which are measured at net asset value.

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, a level 2 measurement, 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 are held in investment funds that are measured at fair value using daily net asset values. In addition, we maintain certain level 3 investments in private equity and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at the fair value utilizing both market- and income-based models, public company comparables, investment cost or 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. The underlying real estate investments are measured at fair value using 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. Our risk management department, which reports to the Chief Financial Officer, has established valuation processes and procedures to ensure that the valuation methodologies for energy marketing transactions are fair and consistent. Methodologies are periodically reviewed and tested to ensure they are representative of the current market dynamics. See "—Recurring Fair Value Measurements" and "—Derivative Instruments" below for additional information.

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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 fixed-rate debt.



	As of June 30, 2012				As of December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,702,500	$	3,141,298	$	2,373,063	$	2,623,993
Fixed-rate debt of VIEs	268,002		298,832		275,738		306,027

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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.



As of June 30, 2012	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Energy Marketing Contracts	$	—	$	783	$	10,645	$	11,428
Nuclear Decommissioning Trust:
Domestic equity	—		52,085		4,780		56,865
International equity	—		26,416		—		26,416
Core bonds	—		27,449		—		27,449
High-yield bonds	—		8,151		—		8,151
Emerging market bonds	—		6,087		—		6,087
Combination debt/equity fund	—		8,275		—		8,275
Real estate securities	—		—		7,449		7,449
Cash equivalents	49		—		—		49
Total Nuclear Decommissioning Trust	49		128,463		12,229		140,741
Trading Securities:
Domestic equity	—		21,520		—		21,520
International equity	—		5,172		—		5,172
Core bonds	—		15,004		—		15,004
Total Trading Securities	—		41,696		—		41,696
Total Assets Measured at Fair Value	$	49	$	170,942	$	22,874	$	193,865

Liabilities:
Energy Marketing Contracts	$	—	$	667	$	3,747	$	4,414

As of December 31, 2011
Assets:
Energy Marketing Contracts	$	—	$	2,401	$	13,330	$	15,731
Nuclear Decommissioning Trust:
Domestic equity	—		53,186		3,931		57,117
International equity	—		22,307		—		22,307
Core bonds	—		20,171		—		20,171
High-yield bonds	—		10,969		—		10,969
Emerging market bonds	—		5,309		—		5,309
Combination debt/equity fund	—		7,251		—		7,251
Real estate securities	—		—		7,095		7,095
Cash equivalents	51		—		—		51
Total Nuclear Decommissioning Trust	51		119,193		11,026		130,270
Trading Securities:
Domestic equity	—		21,175		—		21,175
International equity	—		4,896		—		4,896
Core bonds	—		13,961		—		13,961
Cash equivalents	169		—		—		169
Total Trading Securities	169		40,032		—		40,201
Total Assets Measured at Fair Value	$	220	$	161,626	$	24,356	$	186,202

Liabilities:
Energy Marketing Contracts	$	—	$	2,475	$	3,878	$	6,353
Treasury Yield Hedges	—		34,025		—		34,025
Total Liabilities Measured at Fair Value	$	—	$	36,500	$	3,878	$	40,378

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We do not offset the fair value of energy marketing contracts executed with the same counterparty. As of June 30, 2012, we had no right to reclaim cash collateral and had recorded $1.4 million for our obligation to return cash collateral. As of December 31, 2011, we had no right to reclaim cash collateral and had recorded $2.9 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, 2012.



	Energy Marketing Contracts, net				Nuclear Decommissioning Trust						Net Balance
	Energy Marketing Contracts, net				Domestic Equity			Real Estate Securities			Net Balance
	(In Thousands)
Balance as of March 31, 2012	$	5,343			$	4,100		$	7,271		$	16,714
Total realized and unrealized gains (losses) included in:
Earnings (a)	686				—			—			686
Regulatory assets	751			(b)	—			—			751
Regulatory liabilities	2,943			(b)	104			178			3,225
Purchases	(2,187		)		589			62			(1,536		)
Sales	(346		)		(13		)	(62		)	(421		)
Settlements	(292		)		—			—			(292		)
Balance as of June 30, 2012	$	6,898			$	4,780		$	7,449		$	19,127

Balance as of December 31, 2011	$	9,452			$	3,931		$	7,095		$	20,478
Total realized and unrealized gains (losses) included in:
Earnings (a)	2,172				—			—			2,172
Regulatory assets	(690		)	(b)	—			—			(690		)
Regulatory liabilities	949			(b)	193			354			1,496
Purchases	(3,559		)		669			122			(2,768		)
Sales	(885		)		(13		)	(122		)	(1,020		)
Settlements	(541		)		—			—			(541		)
Balance as of June 30, 2012	$	6,898			$	4,780		$	7,449		$	19,127

_______________


(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.

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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 gains and losses included in earnings are reported in revenues.


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

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Portions of the gains and losses contributing to changes in net assets in the above tables are 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, 2012 and 2011, attributed to level 3 assets and liabilities.



	Three Months Ended June 30, 2012
	Energy Marketing Contracts, net				Nuclear Decommissioning Trust
	Energy Marketing Contracts, net				Domestic Equity		Real Estate Securities			Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(320	)		$	—	$	—	—	$	(320	)
Regulatory assets	769			(b)	—		—		—	769
Regulatory liabilities	1,813			(b)	91		116		—	2,020
Total	$	2,262			$	91	$	116		$	2,469

	Six Months Ended June 30, 2012
Total unrealized gains (losses) included in:
Earnings (a)	$	(124	)		$	—	$	—	—	$	(124	)
Regulatory assets	(644		)	(b)	—		—		—	(644		)
Regulatory liabilities	(185		)	(b)	180		232		—	227
Total	$	(953	)		$	180	$	232		$	(541	)

_______________

(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, 2011
	Energy Marketing Contracts, net				Nuclear Decommissioning Trust
	Energy Marketing Contracts, net				Domestic Equity			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.

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Our level 3 investments require unobservable quantitative inputs to measure fair value. The following table summarizes the quantitative inputs and assumptions for our level 3 investments not measured at net asset value.



	Fair Value as of
	June 30, 2012				Valuation Methodology	Unobservable Inputs	Range of Inputs
	Assets		Liabilities		Valuation Methodology	Unobservable Inputs	Range of Inputs
	(In Thousands)
Electricity - Forwards	$	1,547	$	1,377	Discounted cash flow	Basis (MWh)	$0	to	$40
Gas - Forwards	257		1,408		Discounted cash flow	Basis (mmBtu)	$0	to	$0.20
Options	8,841		962		Discounted cash flow	Basis - Electricity (MWh)	$0	to	$5
						Basis - Gas (mmBtu)	$0	to	$0.25
					Option models	Volatility - Electricity	10%	to	120%
						Volatility - Gas	15%	to	55%
						Correlation	35%	to	85%
Total	$	10,645	$	3,747

Our fair value measurement of our energy marketing contracts is sensitive to level 3 fair value inputs. Increases or decreases to one unobservable input may magnify or mitigate the impact of other inputs. Holding all other inputs constant, an increase (decrease) in a significant unobservable input would typically impact our fair value measurement as follows.



Significant Unobservable Input	Position	Impact on Fair Value Measurement
Basis	Purchase	Increase (decrease)
	Sell	Decrease (increase)
Volatility	Purchase Option	Increase (decrease)
	Sell Option	Decrease (increase)
Correlation	Purchase Option	Decrease (increase)
	Sell Option	Increase (decrease)

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Some of our investments in the nuclear decommissioning trust (NDT) and our trading securities portfolio are measured at net asset value, 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, 2012				As of December 31, 2011				As of June 30, 2012
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	4,780	$	1,246	$	3,931	$	1,914	(a)	(a)
Real estate securities	7,449		—		7,095		—		(b)	(b)
Total Nuclear Decommissioning Trust	12,229		1,246		11,026		1,914

Trading Securities:
Domestic equity	21,520		—		21,175		—		Upon Notice	1 day
International equity	5,172		—		4,896		—		Upon Notice	1 day
Core bonds	15,004		—		13,961		—		Upon Notice	1 day
Total Trading Securities	41,696		—		40,032		—
Total	$	53,925	$	1,246	$	51,058	$	1,914

_______________


(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 making distributions and we expect the other to begin in 2013.


(b)	The nature of this investment requires relatively long holding periods which do not necessarily accommodate ready and complete liquidity. This investment offers quarterly redemptions by way of an investment queue.

Derivative Instruments

Cash Flow Hedges

We entered into treasury yield hedge transactions to hedge our interest rate risk associated with a $125.0 million portion of a forecasted issuance of fixed rate debt. These transactions were designated and qualified as cash flow hedges and 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 gains or losses on these derivative instruments as a regulatory liability or regulatory asset and amortize such amounts to interest expense over the term of the related debt. As of December 31, 2011, we had recorded $34.0 million in other current liabilities on our consolidated balance sheet to reflect the fair value of the treasury yield hedge transactions and $33.8 million in long-term regulatory assets to reflect the effective portion. During the first quarter of 2012, we settled the treasury yield hedge transactions for a cost of $29.7 million, which will be amortized to interest expense over the 30-year term of the debt issued on March 1, 2012. See Note 6, "Debt Financing," for additional information regarding the debt issuance.

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, which may include futures contracts, options, swaps and physical commodity contracts.

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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, 2012
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	$	5,981	Energy marketing contracts	$	4,414
Other assets:
Other	5,447
Total	$	11,428

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 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	$	8,180	Energy marketing contracts	$	6,353
Other assets:
Other	7,551
Total	$	15,731

The following table presents how changes in the fair value of commodity derivative instruments increase (decrease) line items on our condensed consolidated financial statements for the three and six months ended June 30, 2012 and 2011.



	Three Months Ended June 30, 2012						Six Months Ended June 30, 2012
Location	Net Gain Recognized			Net Loss Recognized			Net Gain Recognized		Net Loss Recognized
	(In Thousands)
Revenue	$	2,954		$	—		$	5,022	$	—
Regulatory assets	(627		)	—			—		202
Regulatory liabilities	1,201			—			—		(2,311		)

	Three Months Ended June 30, 2011						Six Months Ended June 30, 2011
Revenues	$	956		$	—		$	—	$	(599	)
Regulatory liabilities	—			(994		)	—		(1,207		)

As of June 30, 2012, and December 31, 2011, we had under contract the following commodity derivatives.



		Net Quantity as of
	Unit of Measure	June 30, 2012	December 31, 2011
Electricity	MWh	1,864,864	1,834,253
Natural gas	MMBtu	2,480,000	1,467,500

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 impact on our consolidated financial results.

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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 and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as 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 numerous 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 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, 2012, and December 31, 2011, was $2.7 million and $3.1 million, respectively, for which we had posted $0.5 million of collateral, including independent amounts, and no collateral, respectively. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2012, and December 31, 2011, we would have been required to provide to our counterparties $0.7 million and $0.5 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 equity and debt 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 hold 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. For the three and six months ended June 30, 2012, we recorded an unrealized loss of $1.8 million and an unrealized gain of $1.8 million, respectively, on these securities. We recorded unrealized gains of $0.6 million and $2.5 million, respectively, during the three and six months ended June 30, 2011.

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Available-for-Sale Securities

We hold investments in equity, debt and real estate securities in a trust 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, 2012, and December 31, 2011. Under normal circumstances, the core bond fund will invest the majority of its assets in investment grade fixed income securities; however, a portion of its assets may be invested in non-investment grade securities. As of June 30, 2012, the fair value of available-for-sale debt securities in the core, high-yield and emerging market bond funds was $41.7 million. As of June 30, 2012, the NDT did not have investments 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 $0.4 million and $0.6 million, respectively, during the three and six months ended June 30, 2012. During the three and six months ended June 30, 2011, we realized gains of $0.3 million and $1.3 million, respectively. 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 cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of June 30, 2012, and December 31, 2011.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of June 30, 2012
Domestic equity	$	50,920	$	5,945	$	—		$	56,865	40	%
International equity	27,799		—		(1,383		)	26,416		19	%
Core bonds	26,554		895		—			27,449		20	%
High-yield bonds	7,762		389		—			8,151		6	%
Emerging market bonds	5,725		362		—			6,087		4	%
Combination debt/equity fund	7,836		439		—			8,275		6	%
Real estate securities	9,784		—		(2,335		)	7,449		5	%
Cash equivalents	49		—		—			49		<1%
Total	$	136,429	$	8,030	$	(3,718	)	$	140,741	100	%

As of December 31, 2011
Domestic equity	$	55,357	$	1,760	$	—		$	57,117	44	%
International equity	24,501		—		(2,194		)	22,307		17	%
Core bonds	19,771		400		—			20,171		16	%
High-yield bonds	11,046		—		(77		)	10,969		8	%
Emerging market bonds	5,301		8		—			5,309		4	%
Combination debt/equity fund	7,524		—		(273		)	7,251		6	%
Real estate securities	9,662		—		(2,567		)	7,095		5	%
Cash equivalents	51		—		—			51		<1%
Total	$	133,213	$	2,168	$	(5,111	)	$	130,270	100	%

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The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of June 30, 2012, and December 31, 2011.




	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, 2012
International equity	$	26,416	$	(1,383	)	$	—	$	—		$	26,416	$	(1,383	)
Real estate securities	—		—			7,449		(2,335		)	7,449		(2,335		)
Total	$	26,416	$	(1,383	)	$	7,449	$	(2,335	)	$	33,865	$	(3,718	)

As of December 31, 2011
International equity	$	22,307	$	(2,194	)	$	—	$	—		$	22,307	$	(2,194	)
High-yield bonds	10,969		(77		)	—		—			10,969		(77		)
Combination debt/equity fund	7,251		(273		)	—		—			7,251		(273		)
Real estate securities	—		—			7,095		(2,567		)	7,095		(2,567		)
Total	$	40,527	$	(2,544	)	$	7,095	$	(2,567	)	$	47,622	$	(5,111	)

5. RATE MATTERS AND REGULATION

KCC Proceedings

On May 29, 2012, the Kansas Corporation Commission (KCC) issued an order allowing us to adjust our prices to include costs associated with investments in environmental projects during 2011. The new prices were effective June 1, 2012, and are expected to increase our annual retail revenues by approximately $19.5 million.

On April 18, 2012, the KCC issued an order expected to increase our annual retail revenues by approximately $50.0 million. In addition, we revised our depreciation rates to reflect changes in the estimated useful lives of some of our depreciable assets. The change in estimate will decrease annual depreciation expense by $43.6 million. Further, we increased our estimate of amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations by $57.9 million. The new prices were effective April 27, 2012. The KCC also approved our request to file an abbreviated rate review within 12 months of this order to update our prices to include capital costs related to environmental projects at La Cygne Generating Station (La Cygne).

Effective April 6, 2012, the KCC authorized an increase in our prices to reflect adjustments to our transmission formula rate as discussed below. The new prices are expected to increase our annual retail revenues by approximately $36.7 million. We expect the KCC to issue a final order on our request by October 2012.

FERC Proceedings

Our transmission formula rate that includes projected 2012 transmission capital expenditures and operating costs was effective January 1, 2012, and is expected to increase annual transmission revenues by approximately $38.2 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.

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6. DEBT FINANCING

On May 17, 2012, Westar Energy issued $300.0 million principal amount of first mortgage bonds at a discount yielding 4.157%, bearing stated interest at 4.125% and maturing on March 1, 2042. These bonds constitute a further issuance of the $250.0 million principal amount of first mortgage bonds issued on March 1, 2012, at a discount yielding 4.13%, bearing stated interest at 4.125% and maturing on March 1, 2042. Proceeds from these issuances of $541.5 million were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds, and for working capital and general corporate purposes.

On May 15, 2012, Westar Energy redeemed $150.0 million aggregate principal amount of 6.10% first mortgage bonds. Additionally, on March 30, 2012, Westar Energy redeemed $57.2 million aggregate principal amount of 5.00% pollution control bonds and KGE redeemed $13.3 million aggregate principal amount of 5.10% pollution control bonds. The bonds were redeemed using short-term debt.

7. TAXES

We recorded income tax expense of $28.3 million with an effective income tax rate of 31% for the three months ended June 30, 2012, and income tax expense of $19.6 million with an effective income tax rate of 30% for the same period of 2011. We recorded income tax expense of $40.8 million with an effective income tax rate of 30% for the six months ended June 30, 2012, and income tax expense of $33.1 million with an effective income tax rate of 30% for the same period of 2011.

In May 2012, the Internal Revenue Service commenced examination of our 2010 federal income tax return and the amended federal income tax returns we filed for years 2007, 2008 and 2009. We have extended the statute of limitation for year 2008 until December 31, 2013.

As of June 30, 2012, and December 31, 2011, our liability for unrecognized income tax benefits was $2.3 million and $2.5 million, respectively. The net decrease 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 significant changes in this liability in the next 12 months.

As of June 30, 2012, and December 31, 2011, we had $0.3 million and $0.2 million, respectively, accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either June 30, 2012, or December 31, 2011.

As of June 30, 2012, and December 31, 2011, we had recorded $1.5 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 federal and state regulations that impose, among other things, limitations on pollutants generated from our operations, including sulfur dioxide (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, 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) and Environmental Protection Agency (EPA), 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 EPA sets National Ambient Air Quality Standards (NAAQS) for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, CO 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. 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 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. Recently the Wichita area exceeded the 8-hour ozone standard and may be designated nonattainment in the future.

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In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We continue to communicate with our regulators regarding these standards and 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 and operating 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.

In comparison to a general rate review, the environmental cost recovery rider (ECRR) reduces the amount of time it takes to begin collecting in retail prices the costs associated with capital expenditures for qualifying environmental improvements. We are not allowed to use the ECRR to collect costs associated with our approximately $600.0 million capital investment for environmental upgrades at La Cygne. We must file for a general review of our rates or an abbreviated rate review with the KCC in order to collect such costs. As previously discussed, the KCC approved our request to file an abbreviated rate review within 12 months of its April 18, 2012, order to update our prices to include capital costs related to environmental projects at La Cygne. In order to change our prices to collect increased operating and maintenance costs, we must also file a general rate review with the KCC.

Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In December 2011, the EPA published Mercury and Air Toxics Standards (MATS) for power plants, which replaces the prior federal Clean Air Mercury Rule (CAMR) and requires significant reductions in mercury, acid gases and other emissions. Companies impacted by the new standards will have up to three years, or four years with approval from a state environmental regulatory agency, and in certain limited circumstances up to five years, to comply. We have obtained approval by our state environmental regulatory agency and expect to be compliant with the new standards within four years. We continue to evaluate the new standards and believe that our related investment could be approximately $40.0 million.

In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) which requires 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were scheduled to begin January 1, 2012, with further reductions required beginning January 1, 2014. The EPA issued federal implementation plans for each state covered by CSAPR, but would allow these states to submit their own implementation plans starting as early as 2013. In October 2011, we and numerous other parties filed legal challenges to CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.

In December 2011, the EPA published a final supplemental rule to CSAPR requiring five states, including Missouri and Oklahoma, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this rule were scheduled to begin May 1, 2012. Although Kansas was included in the original proposed rule, the final supplemental rule instead calls for the EPA to revisit Kansas' status under this supplemental rule once Kansas submits an ozone state implementation plan, which must occur within 12 months from the date the EPA issues a state implementation request to Kansas. The EPA has not yet issued such a request to Kansas.

On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay CSAPR, including the final supplemental rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. On April 13, 2012, the court heard arguments to this case. As the outcome of the judicial review and any other possible legal or Congressional challenges are uncertain, we are unable to determine what impact CSAPR may ultimately have on our operations and consolidated financial results, but it could be material.

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Greenhouse Gases

Under EPA regulations known as the Tailoring Rule, the EPA is regulating greenhouse gas (GHG) emissions from certain stationary sources. 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 include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), are 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 regulations on our operations and consolidated financial results, but we believe the cost of compliance with the regulations could be material.

Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy 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 met the 2011 requirement using approximately 300 megawatts (MW) of qualifying wind generation facilities along with renewable energy credits. Beginning in late 2012, we will purchase under 20-year supply contracts the renewable energy produced from an additional approximately 370 MW of wind generation, which will allow us to satisfy the net renewable generation requirement through 2015 and contribute toward meeting the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

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, ONEOK Inc. (ONEOK) assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million and terminates in November 2012.

EPA Consent Decree

As part of the settlement of a lawsuit filed by the Department of Justice on behalf of the EPA, we will install selective catalytic reduction equipment (SCR) on one of three Jeffrey Energy Center (JEC) coal units by the end of 2014, which we estimate will cost approximately $240.0 million. 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 SCR on another JEC unit by the end of 2016, if needed to meet plant-wide NOx reduction targets. We plan to recover the costs to install these systems through our ECRR. Recovery of all or part of such costs remains subject to the approval of our regulators.

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. Following additional communications with FERC staff, FERC staff further revised its preliminary conclusions to allege that we have received $0.9 million of unjust profits and failed to pay $0.8 million to the SPP for transmission service. Although we continue to believe our use of transmission service was in compliance with FERC orders and SPP tariffs, we recorded an estimated liability of $0.5 million as of June 30, 2012, and December 31, 2011, related to the potential settlement of this investigation and the risks of litigating this matter to a final outcome. 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 payments for alleged unjust profits and unpaid transmission costs as well as penalties, 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.

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9. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various 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 effect on our consolidated financial results. See Note 5, "Rate Matters and Regulation," and Note 8, "Commitments and Contingencies," for additional information.

10. PENSION AND POST-RETIREMENT BENEFIT PLANS

The following tables summarize 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,	2012			2011			2012			2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	4,889		$	4,021		$	514		$	450
Interest cost	9,894			9,960			1,574			1,704
Expected return on plan assets	(8,070		)	(7,772		)	(1,372		)	(1,300		)
Amortization of unrecognized:
Transition obligation, net	—			—			978			978
Prior service costs	153			303			631			723
Actuarial loss, net	8,194			5,915			376			97
Net periodic cost before regulatory adjustment	15,060			12,427			2,701			2,652
Regulatory adjustment	(2,005		)	(5,641		)	(278		)	329
Net periodic cost	$	13,055		$	6,786		$	2,423		$	2,981



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2012			2011			2012			2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	9,777		$	8,038		$	1,029		$	902
Interest cost	19,789			19,915			3,149			3,397
Expected return on plan assets	(16,142		)	(15,544		)	(2,746		)	(2,501		)
Amortization of unrecognized:
Transition obligation, net	—			—			1,956			1,956
Prior service costs	307			606			1,262			1,262
Actuarial loss, net	16,389			11,830			752			351
Net periodic cost before regulatory adjustment	30,120			24,845			5,402			5,367
Regulatory adjustment	(9,250		)	(11,267		)	40			626
Net periodic cost	$	20,870		$	13,578		$	5,442		$	5,993

During the six months ended June 30, 2012 and 2011, we contributed $49.4 million and $41.1 million, respectively, to the Westar Energy pension trust.

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11. WOLF CREEK PENSION AND POST-RETIREMENT BENEFIT PLANS

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 tables summarize the net periodic costs for KGE's 47% share of the Wolf Creek pension and post-retirement benefit plans prior to the effects of capitalization.



	Pension Benefits						Post-retirement Benefits
Three Months Ended June 30,	2012			2011			2012		2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	1,516		$	1,219		$	48	$	29
Interest cost	1,884			1,821			103		104
Expected return on plan assets	(1,644		)	(1,428		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			13			14		14
Prior service costs	1			4			—		(8		)
Actuarial loss, net	1,341			798			58		38
Net periodic cost before regulatory adjustment	3,098			2,427			223		177
Regulatory adjustment	(484		)	(663		)	—		—
Net periodic cost	$	2,614		$	1,764		$	223	$	177



	Pension Benefits						Post-retirement Benefits
Six Months Ended June 30,	2012			2011			2012		2011
	(In Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	3,031		$	2,479		$	96	$	83
Interest cost	3,769			3,685			205		229
Expected return on plan assets	(3,289		)	(2,953		)	—		—
Amortization of unrecognized:
Transition obligation, net	—			26			29		29
Prior service costs	3			8			—		—
Actuarial loss, net	2,683			1,793			117		114
Net periodic cost before regulatory adjustment	6,197			5,038			447		455
Regulatory adjustment	(1,514		)	(1,320		)	—		—
Net periodic cost	$	4,683		$	3,718		$	447	$	455

During the six months ended June 30, 2012 and 2011, we funded $9.0 million and $7.1 million, respectively, of Wolf Creek's pension plan contribution.

12. COMMON AND PREFERRED STOCK

Common Stock

In May 2012, Westar Energy entered into forward sale transactions with respect to an aggregate of approximately 1.1 million shares of common stock pursuant to an existing forward sale agreement. Westar Energy must settle such transactions within 18 months of the date each transaction was entered. Assuming physical share settlement of the forward sale transactions as of June 30, 2012, Westar Energy would have received aggregate proceeds of approximately $29.3 million based on a forward price of $27.46 per share.

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Preferred Stock Redemption

In May 2012, Westar Energy provided an irrevocable notice of redemption to holders of all of Westar Energy's preferred shares. Accordingly, we reduced preferred equity to zero, recognized the obligation to redeem the preferred shares as a liability, and recognized the redemption premium as a preferred stock dividend during the three months ended June 30, 2012. Payment is due to holders of the preferred shares effective July 1, 2012. The table below shows the redemption amounts for all series of preferred stock.



Rate		Shares	Principal Outstanding		Call Price		Premium		Total Cost to Redeem
(Dollars in Thousands)
4.50	%	121,613	$	12,161	108.0	%	$	973	$	13,134
4.25	%	54,970	5,497		101.5	%	82		5,579
5.00	%	37,780	3,778		102.0	%	76		3,854
		214,363	$	21,436			$	1,131	$	22,567

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 power 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 the 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.

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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 related to the VIEs described above.



	As of		As of
	June 30, 2012		December 31, 2011
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	327,734	$	333,494
Regulatory assets (a)	5,400		4,915

Liabilities:
Current maturities of long-term debt of variable interest entities	$	45,853	$	28,114
Accrued interest (b)	4,227		4,448
Long-term debt of variable interest entities, net	223,506		249,283

_______________

(a) Included in long-term 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 purchase of the 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.

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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," "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 operating results for the three and six months ended June 30, 2012, compared to the same periods of 2011, our general financial condition and significant changes that occurred during 2012. 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 basic EPS.



	Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011		Change		2012		2011		Change
	(Dollars In Thousands, Except Per Share Amounts)

Net income attributable to common stock	$	61,361	$	43,887	$	17,474	$	88,642	$	75,227	$	13,415
Earnings per common share, basic	0.48		0.38		0.10		0.70		0.66		0.04

The increases shown in the above table were due primarily to implementing the April 18, 2012, KCC rate order, which resulted in higher retail prices, and, for the three months ended June 30, 2012, higher retail electricity sales, as well as our having recorded additional corporate-owned life insurance (COLI) benefits. These increases were offset partially by higher operating costs due in part to implementing the April 18, 2012, KCC rate order. See the discussion under "—Operating Results" below for additional information. In addition, basic EPS was also impacted by increases in average equivalent common shares outstanding due primarily to our having issued additional shares in the latter part of 2011 to settle forward sale transactions.

Rate Case Agreement

On April 18, 2012, the KCC issued an order permitting recovery of pension costs and greater amounts of tree trimming costs. As a result of this order, we expect selling, general and administrative expense to increase by $32.1 million and the cost of operating and maintaining our distribution system to increase by $10.9 million on an annualized basis. In addition, we revised our depreciation rates to reflect changes in the estimated useful lives of some of our depreciable assets. The change in estimate will decrease annual depreciation expense by $43.6 million. However, decreased depreciation expense as a result of lower depreciation rates may be offset by additions to plant, property and equipment. Further, we increased our estimate of amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations by $57.9 million.

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Current Trends

The following is an update to and is to be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our 2011 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 may potentially need 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 all such costs to be reflected in the prices we are allowed to charge, we cannot assure that all such costs will be recovered in a timely manner. See Note 8 of the Notes to Condensed Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding environmental laws and regulations.

Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In December 2011, the EPA published MATS for power plants, which replaces the prior federal CAMR and requires significant reductions in mercury, acid gases and other emissions. Companies impacted by the new standards will have up to three years, or four years with approval from a state environmental regulatory agency, and in certain limited circumstances up to five years, to comply. We have obtained approval by our state environmental regulatory agency and expect to be compliant with the new standards within four years. We continue to evaluate the new standards and believe that our related investment could be approximately $40.0 million.

In July 2011, the EPA finalized CSAPR which requires 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were scheduled to begin January 1, 2012, with further reductions required beginning January 1, 2014. The EPA issued federal implementation plans for each state covered by CSAPR, but would allow these states to submit their own implementation plans starting as early as 2013.

In October 2011, the EPA issued a proposed amendment to CSAPR that, according to the EPA, would slightly ease the new emission standards and defer the effective date of certain penalty provisions from January 1, 2012, to January 1, 2014.

In December 2011, the EPA published a final supplemental rule to CSAPR requiring five states, including Missouri and Oklahoma, to make summertime reductions in NOx emissions under an ozone-season control program implemented under CSAPR. Reductions in ozone-season NOx under this rule begin May 1, 2012. Although Kansas was included in the original proposed rule, the final supplemental rule instead calls for the EPA to revisit Kansas' status under this supplemental rule once Kansas submits an ozone state implementation plan, which must occur within 12 months from the date the EPA issues a state implementation request to Kansas. The EPA has not yet issued such a request to Kansas.

In October 2011, we and numerous other parties filed legal challenges to CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit. On December 30, 2011, the court issued its ruling to stay CSAPR, including the final supplemental rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. On April 13, 2012 the court heard arguments to this case. As the outcome of the judicial review and any other possible legal or Congressional challenges are uncertain, we are unable to determine what impact CSAPR may ultimately have on our operations and consolidated financial results, but it could be material.

Greenhouse Gases

On March 27, 2012, the EPA proposed a New Source Performance Standard that would limit carbon dioxide emissions for new electric generating units. We are currently evaluating the proposal and believe it could impact our future generation plans if it becomes a final rule.

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Under EPA regulations known as the Tailoring Rule, the EPA is regulating GHG emissions from certain stationary sources. 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 PSD. Obligations relating to Title V permits include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), are required to implement 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 regulations on our operations and consolidated financial results, but we believe the costs to comply with the regulations could be material.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash, which we must handle, dispose of, recycle or process. We recycle some of our fly ash and bottom ash production, principally by selling to the aggregate industry. This is referred to as beneficial use. In June 2010, the EPA proposed a rule to regulate CCBs under the Resource Conservation and Recovery Act (RCRA). The proposed rule provides two possible options for CCB regulation, both of which technically would allow for the continued beneficial use of CCBs, but we believe might actually curtail or impair beneficial use to the extent we are able to recycle it today. The first option would subject CCBs to regulation as special waste under Subtitle C of RCRA when disposed of in landfills or surface impoundments. The second option would regulate CCBs as non-hazardous solid waste under Subtitle D of RCRA. The EPA is expected to issue a final rule in 2013. While we cannot at this time estimate the impact and costs associated with future regulations of CCBs, we believe the impact on our operations and consolidated financial results could be material.

National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets NAAQS for six criteria emissions considered harmful to public health and the environment, including PM, NOx, CO 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. 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 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. Recently the Wichita area exceeded the 8-hour ozone standard and may be designated nonattainment in the future.

Particulate matter, principally ash, is a byproduct of coal combustion. On June 14, 2012, the EPA proposed to strengthen the fine PM NAAQS. We are currently evaluating the proposal. The EPA expects to issue a final rule by the end of 2012; however, because the rule has yet to be finalized, we cannot predict the impact it may have on our operations or consolidated financial results, but it could be material.

The EPA had been in the process of revising the NAAQS for ozone. However, in September 2011, the President of the United States ordered the EPA to withdraw its proposal. Work is currently underway to support the EPA's planned reconsideration of the standards in 2013.

Water

Some water used in our operations is later discharged. This water may contain substances deemed to be pollutants. The EPA plans to propose revisions to the rules governing such water discharges from coal-fired power plants later this year with final action on the proposed rules expected to occur in 2014. Although we cannot at this time determine the impact of any new regulations, more stringent regulations could have a material impact on our operations and consolidated financial results.

In April 2011, the EPA issued a proposed rule that would set stricter technology standards for cooling water intake structures at power plants over concerns about aquatic life. We are currently evaluating the proposal as well as a recent information request from the EPA. The EPA is expected to finalize the rule in 2013; however, because the rule has yet to be finalized, we cannot predict the impact it may have on our operations or consolidated financial results, but it could be material.

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Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy 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 met the 2011 requirement using approximately 300 MW of qualifying wind generation facilities along with renewable energy credits. Beginning in late 2012, we will purchase under 20-year supply contracts the renewable energy produced from an additional approximately 370 MW of wind generation, which will allow us to satisfy the net renewable generation requirement through 2015 and contribute toward meeting the increased requirements beginning in 2016. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.

Wolf Creek Regulation and Operating Costs

In January 2012, Wolf Creek experienced a loss of off site power that resulted in an unscheduled outage, with the plant returning to normal operation in March 2012. The NRC conducted an investigation and increased its oversight of Wolf Creek following the loss of off site power. Further increases in the NRC's oversight and involvement in Wolf Creek's operations may occur in the future. Operating costs at Wolf Creek increased in the six months ended June 30, 2012, due to the unscheduled outage. We expect future increases in operating costs due to increased NRC oversight and efforts to comply with new industry-wide regulations adopted by the NRC earlier this year after a review of U.S. nuclear power plant safety prompted by Japan's Fukushima Daiichi nuclear power plant event in 2011.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our condensed 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 2011 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, 2011, through June 30, 2012, we have not experienced any significant changes in our critical accounting estimates. For additional information, see our 2011 Form 10-K.

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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 prices charged to certain wholesale customers taking service under cost-based tariffs.

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.

Our 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.

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Three and Six Months Ended June 30, 2012, Compared to Three and Six Months Ended June 30, 2011

Below we discuss our operating results for the three and six months ended June 30, 2012, compared to the results for the three and six months ended June 30, 2011. 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,
	2012			2011			Change			% Change		2012			2011			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	176,893		$	157,120		$	19,773		12.6		$	315,311		$	310,028		$	5,283		1.7
Commercial	170,132			153,554			16,578			10.8		299,782			282,382			17,400			6.2
Industrial	95,960			91,245			4,715			5.2		181,380			170,441			10,939			6.4
Other retail	(2,363		)	(2,440		)	77			3.2		(5,281		)	(5,455		)	174			3.2
Total Retail Revenues	440,622			399,479			41,143			10.3		791,192			757,396			33,796			4.5
Wholesale	68,971			77,515			(8,544		)	(11.0	)	140,183			156,109			(15,926		)	(10.2	)
Transmission (a)	49,380			39,160			10,220			26.1		95,343			76,336			19,007			24.9
Other	7,289			8,738			(1,449		)	(16.6	)	15,222			16,770			(1,548		)	(9.2	)
Total Revenues	566,262			524,892			41,370			7.9		1,041,940			1,006,611			35,329			3.5
OPERATING EXPENSES:
Fuel and purchased power	147,680			152,973			(5,293		)	(3.5	)	275,334			287,157			(11,823		)	(4.1	)
Operating and maintenance	156,470			137,254			19,216			14.0		312,514			274,606			37,908			13.8
Depreciation and amortization	66,299			71,089			(4,790		)	(6.7	)	139,579			141,348			(1,769		)	(1.3	)
Selling, general and administrative	62,711			55,970			6,741			12.0		110,046			104,734			5,312			5.1
Total Operating Expenses	433,160			417,286			15,874			3.8		837,473			807,845			29,628			3.7
INCOME FROM OPERATIONS	133,102			107,606			25,496			23.7		204,467			198,766			5,701			2.9
OTHER INCOME (EXPENSE):
Investment (losses) earnings	(598		)	1,374			(1,972		)	(143.5	)	3,727			3,342			385			11.5
Other income	7,537			2,557			4,980			194.8		21,127			4,806			16,321			339.6
Other expense	(2,416		)	(3,113		)	697			22.4		(7,969		)	(8,482		)	513			6.0
Total Other Income (Expense)	4,523			818			3,705			452.9		16,885			(334		)	17,219			(b)
Interest expense	44,823			43,300			1,523			3.5		86,869			86,838			31			(c)
INCOME BEFORE INCOME TAXES	92,802			65,124			27,678			42.5		134,483			111,594			22,889			20.5
Income tax expense	28,340			19,599			8,741			44.6		40,783			33,112			7,671			23.2
NET INCOME	64,462			45,525			18,937			41.6		93,700			78,482			15,218			19.4
Less: Net income attributable to noncontrolling interests	1,728			1,396			332			23.8		3,442			2,770			672			24.3
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY	62,734			44,129			18,605			42.2		90,258			75,712			14,546			19.2
Preferred dividends	1,373			242			1,131			467.4		1,616			485			1,131			233.2
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	61,361		$	43,887		$	17,474		39.8		$	88,642		$	75,227		$	13,415		17.8
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY	$	0.48		$	0.38		$	0.10		26.3		$	0.70		$	0.66		$	0.04		6.1

_______________

(a)

Reflects revenue from an SPP network transmission tariff. For the three and six months ended June 30, 2012, our SPP network transmission costs were $42.3 million and $81.6 million, respectively. These amounts, less administration costs of $6.8 million and $13.0 million, respectively, were returned to us as revenue. 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 administration costs of $4.1 million and $8.3 million, respectively, were returned to us as revenue.


(b)	Change greater than 1000%.


(c)	Change less than 0.1%.

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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, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. 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, 2012 and 2011.



	Three Months Ended June 30,											Six Months Ended June 30,
	2012			2011			Change			% Change		2012			2011			Change			% Change
	(Dollars In Thousands)
REVENUES:
Residential	$	176,893		$	157,120		$	19,773		12.6		$	315,311		$	310,028		$	5,283		1.7
Commercial	170,132			153,554			16,578			10.8		299,782			282,382			17,400			6.2
Industrial	95,960			91,245			4,715			5.2		181,380			170,441			10,939			6.4
Other retail	(2,363		)	(2,440		)	77			3.2		(5,281		)	(5,455		)	174			3.2
Total Retail Revenues	440,622			399,479			41,143			10.3		791,192			757,396			33,796			4.5
Wholesale	68,971			77,515			(8,544		)	(11.0	)	140,183			156,109			(15,926		)	(10.2	)
Transmission	49,380			39,160			10,220			26.1		95,343			76,336			19,007			24.9
Other	7,289			8,738			(1,449		)	(16.6	)	15,222			16,770			(1,548		)	(9.2	)
Total Revenues	566,262			524,892			41,370			7.9		1,041,940			1,006,611			35,329			3.5
Less: Fuel and purchased power expense	147,680			152,973			(5,293		)	(3.5	)	275,334			287,157			(11,823		)	(4.1	)
SPP network transmission costs	42,265			32,685			9,580			29.3		81,627			64,736			16,891			26.1
Gross Margin	$	376,317		$	339,234		$	37,083		10.9		$	684,979		$	654,718		$	30,261		4.6

The following table reflects changes in electricity sales for the three and six months ended June 30, 2012 and 2011. 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,
	2012	2011	Change		% Change		2012	2011	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	1,629	1,549	80		5.2		3,044	3,207	(163	)	(5.1	)
Commercial	1,977	1,890	87		4.6		3,626	3,594	32		0.9
Industrial	1,418	1,438	(20	)	(1.4	)	2,779	2,776	3		0.1
Other retail	22	22	—		—		42	43	(1	)	(2.3	)
Total Retail	5,046	4,899	147		3.0		9,491	9,620	(129	)	(1.3	)
Wholesale	1,604	1,776	(172	)	(9.7	)	3,298	3,687	(389	)	(10.6	)
Total	6,650	6,675	(25	)	(0.4	)	12,789	13,307	(518	)	(3.9	)

Gross margin increased for the three and six months ended June 30, 2012, due primarily to higher retail revenues that were the result principally of higher prices. Contributing to the increase in retail revenues for the three months ended June 30, 2012, were higher retail electricity sales attributable primarily to warmer weather. As measured by cooling degree days, the weather during the three months ended June 30, 2012, was 19% warmer than the same period of 2011.

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Income from operations is the most directly comparable measure to our presentation of 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, 2012 and 2011.



	Three Months Ended June 30,									Six Months Ended June 30,
	2012		2011		Change			% Change		2012		2011		Change			% Change
	(Dollars In Thousands)
Gross margin	$	376,317	$	339,234	$	37,083		10.9		$	684,979	$	654,718	$	30,261		4.6
Add: SPP network transmission costs	42,265		32,685		9,580			29.3		81,627		64,736		16,891			26.1
Less: Operating and maintenance expense	156,470		137,254		19,216			14.0		312,514		274,606		37,908			13.8
Depreciation and amortization expense	66,299		71,089		(4,790		)	(6.7	)	139,579		141,348		(1,769		)	(1.3	)
Selling, general and administrative expense	62,711		55,970		6,741			12.0		110,046		104,734		5,312			5.1
Income from operations	$	133,102	$	107,606	$	25,496		23.7		$	204,467	$	198,766	$	5,701		2.9

Operating Expenses and Other Income and Expense Items



	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	156,470	$	137,254	$	19,216	14.0	$	312,514	$	274,606	$	37,908	13.8

Operating and maintenance expense increased due principally to:


•	higher SPP network transmission costs of $9.6 million and $16.9 million, respectively, most of which is recovered in revenues;


•	higher costs for tree trimming and other reliability activities of $3.1 million and $4.2 million, respectively;


•	increases in property taxes of $2.9 million and $5.3 million, respectively, most of which is offset in retail revenues;


•	for the three months ended June 30, 2012, higher costs of $2.4 million related to the operation and maintenance of our steam powered plants; and


•	for the six months ended June 30, 2012, higher costs at Wolf Creek of $9.4 million, which were the result primarily of maintenance costs incurred during an unscheduled outage.



	Three Months Ended June 30,									Six Months Ended June 30,
	2012		2011		Change			% Change		2012		2011		Change			% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	66,299	$	71,089	$	(4,790	)	(6.7	)	$	139,579	$	141,348	$	(1,769	)	(1.3	)

Depreciation and amortization expense decreased as a result primarily of our having reduced depreciation rates to reflect changes in the estimated useful lives of some of our depreciable assets.

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	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	62,711	$	55,970	$	6,741	12.0	$	110,046	$	104,734	$	5,312	5.1

Selling, general and administrative expense increased due primarily to higher pension and other employee benefit costs of $11.1 million and $11.9 million, respectively. Partially offsetting these increases were lower legal fees of $6.2 million and $7.9 million, respectively. During the three and six months ended June 30, 2011, we incurred legal fees for arbitration and settlement proceedings with two former executive officers. There were no similar legal fees during the same periods of 2012.



	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Other income	$	7,537	$	2,557	$	4,980	194.8	$	21,127	$	4,806	$	16,321	339.6

Other income increased due principally to:


•	our having recorded an additional $3.4 million and $12.6 million, respectively, in COLI benefits; and


•	increases in equity AFUDC of $1.2 million and $3.4 million, respectively, which reflect increased construction activity.



	Three Months Ended June 30,							Six Months Ended June 30,
	2012		2011		Change		% Change	2012		2011		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	28,340	$	19,599	$	8,741	44.6	$	40,783	$	33,112	$	7,671	23.2

Income tax expense increased due principally to higher income before income taxes.

FINANCIAL CONDITION

A number of factors affected amounts recorded on our balance sheet as of June 30, 2012, compared to December 31, 2011.



	As of		As of
	June 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Restricted cash	$	22,567	$	—	$	22,567		(a)
Cumulative preferred stock	—		21,436		(21,436		)	(100.0	)

_______________

(a)Change greater than 1000%.

Restricted cash increased and cumulative preferred stock decreased due to Westar Energy having provided notice to holders of its preferred stock that it would redeem all outstanding shares. See Note 12 of the Notes to Condensed Consolidated Financial Statements, "Common and Preferred Stock," for additional information.

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	As of		As of
	June 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	256,316	$	229,118	$	27,198	11.9

Fuel inventory and supplies increased due principally to a $29.4 million increase in coal inventory. Coal inventory volumes increased 43% resulting from less coal being consumed due to a mild winter and increased usage of our other plants.



	As of		As of
	June 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Taxes receivable	$	—	$	5,334	$	(5,334	)	(100.0	)

Tax receivable decreased due primarily to our having received $5.9 million of tax refunds.



	As of		As of
	June 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	1,020,862	$	1,046,090	$	(25,228	)	(2.4	)
Regulatory liabilities	337,127		271,387		65,740			24.2
Net regulatory assets	$	683,735	$	774,703	$	(90,968	)	(11.7	)

Regulatory assets decreased due principally to the following reasons:

•a $12.9 million decrease in deferred employee benefit costs;

•a $7.0 million decrease in previously deferred storm costs; and

•a $6.8 million decrease in amounts deferred for the Wolf Creek outage.

Regulatory liabilities increased due principally to revising our estimate of amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations by $57.9 million.



	As of		As of
	June 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	45,853	$	28,114	$	17,739		63.1
Long-term debt of variable interest entities, net	223,506		249,283		(25,777		)	(10.3	)
Total long-term debt of variable interest entities	$	269,359	$	277,397	$	(8,038	)	(2.9	)

Current maturities of long-term debt of variable interest entities increased due primarily to a reclassification from long-term debt of variable interest entities, net, for an expected principal payment to be made in the next 12 months by the VIE that holds the 50% leasehold interest in La Cygne unit 2.



	As of		As of
	June 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Long-term debt, net	$	2,818,966	$	2,491,109	$	327,857	13.2

Long-term debt, net increased due principally to the issuance of $550.0 million principal amount of first mortgage bonds. Partially offsetting this increase was the redemption of $220.5 million of bonds as discussed in Note 6 of the Notes to Condensed Consolidated Financial Statements, "Debt Financing."

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	As of		As of
	June 30, 2012		December 31, 2011		Change		% Change
	(Dollars in Thousands)
Deferred income taxes	$	1,138,708	$	1,110,463	$	28,245	2.5

Net deferred income taxes increased due primarily to the use of bonus and accelerated depreciation methods.



	As of		As of
	June 30, 2012		December 31, 2011		Change			% Change
	(Dollars in Thousands)
Accrued employee benefits	$	546,793	$	592,617	$	(45,824	)	(7.7	)

Accrued employee benefits decreased due primarily to our having contributed $49.4 million to the Westar Energy pension trust and our having funded $9.0 million of Wolf Creek's pension plan contribution.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, Westar Energy's revolving credit facilities and commercial paper program, 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 temporary borrowings from the commercial paper program and revolving credit facilities. To meet the cash requirements for our capital investments, we expect to use internally generated cash, temporary borrowings from commercial paper issuances and revolving credit facilities, as well as the issuance of debt and equity securities in the capital markets. We also use proceeds from the issuance of securities to repay short-term borrowings, which are principally related to investments in capital equipment, when such balances are of sufficient size and it makes economic sense to do so, 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.

Short-Term Borrowings

Westar Energy has entered into a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy's revolving credit facilities described below. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to repay borrowings under Westar Energy's revolving credit facilities, for working capital and/or for other general corporate purposes. As of July 31, 2012, Westar Energy had issued $358.6 million of commercial paper.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million, which terminate on September 29, 2016, and February 18, 2015, respectively. As long as there is no default under the facilities, each may be extended up to an additional two years and the aggregate amount of borrowings under the facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE first mortgage bonds. As of July 31, 2012, no amounts were borrowed and $13.9 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. In addition, total combined borrowings under the commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time.

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Debt Financing

Debt Covenants

We remain in compliance with our debt covenants.

Impact of Credit Ratings on Debt Financing

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, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy's revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy's ability to borrow under the credit facilities and commercial paper program are 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.

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On January 6, 2012, Moody's upgraded its credit ratings for Westar Energy and KGE first mortgage bonds/senior secured debt to A3 from Baa1. Moody's also upgraded its credit rating for Westar Energy unsecured debt to Baa2 from Baa3 and assigned a P-2 rating to Westar Energy's commercial paper program. As of July 31, 2012, our ratings with the agencies are as shown in the table below.



	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Unsecured Debt Rating	Westar Energy Commercial Paper	Rating Outlook
Moody’s	A3	A3	Baa2	P-2	Stable
S&P	BBB+	BBB+	BBB	A-2	Stable
Fitch	A-	A-	BBB+	F2	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, 2012, and December 31, 2011, was $2.7 million and $3.1 million, respectively, for which we had posted $0.5 million of collateral, including independent amounts, and no collateral, respectively. If all credit-risk-related contingent features underlying these agreements had been triggered as of June 30, 2012, and December 31, 2011, we would have been required to provide to our counterparties $0.7 million and $0.5 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Common and Preferred Stock

Common Stock

Preferred Stock Redemption

In May 2012, Westar Energy provided an irrevocable notice of redemption to holders of all of Westar Energy's preferred shares. Pursuant to Westar Energy's Articles of Incorporation, we deposited cash in a separate account to effect the redemption of all of our preferred stock outstanding. Payment is due to holders of the preferred shares effective July 1, 2012. The table below shows the redemption amounts for all series of preferred stock.



Rate		Shares	Principal Outstanding		Call Price		Premium		Total Cost to Redeem
(Dollars in Thousands)
4.50	%	121,613	$	12,161	108.0	%	$	973	$	13,134
4.25	%	54,970	5,497		101.5	%	82		5,579
5.00	%	37,780	3,778		102.0	%	76		3,854
		214,363	$	21,436			$	1,131	$	22,567

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Summary of Cash Flows



	Six Months Ended June 30,
	2012			2011			Change			% Change
	(Dollars In Thousands)
Cash flows from (used in):
Operating activities	$	103,179		$	71,447		$	31,732		44.4
Investing activities	(419,790		)	(359,199		)	(60,591		)	(16.9	)
Financing activities	319,726			292,106			27,620			9.5
Net increase in cash and cash equivalents	$	3,115		$	4,354		$	(1,239	)	(28.5	)

Cash Flows from Operating Activities

Cash flows from operating activities increased due principally to our having paid $37.8 million less for fuel and purchased power and our having paid $26.5 million in 2011 to a former executive officer for compensation, his legal fees and other expenses. Increases were partially offset by our having paid $29.7 million in 2012 to settle treasury yield hedge transactions and our having contributed $10.0 million more to pension and post-retirement benefit plans.

Cash Flows used in Investing Activities

Cash flows used in investing activities increased due primarily to our having invested $72.1 million more in additions to property, plant and equipment. Partially offsetting this increased investment was our having received $15.6 million more in proceeds from our investment in COLI.

Cash Flows from Financing Activities

Cash flows from financing activities increased due primarily to our having received $541.5 million in proceeds from long-term debt issuances. Proceeds received were offset partially by our having paid $220.4 million more for long-term debt retirements, a $180.0 million decrease in short-term borrowings, our having received $65.5 million less from common stock issuances, our having established a $22.6 million restricted cash account to fund the redemption of preferred stock, our having repaid $15.2 million more for borrowings against the cash surrender value of COLI and our having paid $10.9 million more for dividends.

Pension Contribution

During the six months ended June 30, 2012, we contributed $49.4 million to the Westar Energy pension trust and funded $9.0 million of Wolf Creek's pension plan contribution.

OFF-BALANCE SHEET ARRANGEMENTS

From December 31, 2011, through June 30, 2012, our off-balance sheet arrangements did not change materially. For additional information, see our 2011 Form 10-K.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

From December 31, 2011, through June 30, 2012, our contractual obligations and commercial commitments did not change materially outside the ordinary course of business. For additional information, see our 2011 Form 10-K.

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OTHER INFORMATION

Changes in Prices

KCC Proceedings

On May 29, 2012, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in environmental projects during 2011. The new prices were effective June 1, 2012, and are expected to increase our annual retail revenues by approximately $19.5 million.

On April 18, 2012, the KCC issued an order expected to increase our annual retail revenues by approximately $50.0 million. The new prices were effective April 27, 2012. The KCC also approved our request to file an abbreviated rate review within 12 months of this order to update our prices to include capital costs related to environmental projects at La Cygne.

FERC Proceedings

Wolf Creek Outage

Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. However, as a result of an unscheduled maintenance outage at Wolf Creek in early 2012 coupled with the longer than planned refueling and maintenance outage in the spring of 2011, the next planned refueling and maintenance outage has been moved from fall 2012 to the first quarter of 2013.

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Fair Value of Energy Marketing Contracts

The following table shows the net fair value of energy marketing contracts outstanding as of June 30, 2012.



	Fair Value of Contracts
	(In Thousands)

Net fair value of contracts outstanding as of December 31, 2011 (a)	$	9,378
Contracts outstanding at the beginning of the period that were realized or otherwise settled during the period	(1,528		)
Changes in fair value of contracts outstanding at the beginning and end of the period	(896		)
Fair value of new contracts entered into during the period	60
Net fair value of contracts outstanding as of June 30, 2012 (b)	$	7,014

_______________

(a) Approximately $0.4 million and $6.2 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.

(b) Approximately $0.6 million and $3.9 million of the fair value of energy marketing contracts were recognized as a regulatory asset and regulatory liability, respectively.

The sources of the fair values of the financial instruments related to these contracts and the maturity periods of the contracts as of June 30, 2012, 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)	$	7,585		$	1,271	$	6,314		$	—	$	—
Prices based on option pricing models (options and other) (a)	(571		)	296		(867		)	—		—
Total fair value of contracts outstanding	$	7,014		$	1,567	$	5,447		$	—	$	—

_______________

(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, 2011, to June 30, 2012, no significant changes occurred in our market risk exposure. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our 2011 Form 10-K for additional information.

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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, 2012, that 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 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 risk factors did not change materially from December 31, 2011, through June 30, 2012. For additional information, see our 2011 Form 10-K.

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

During the three-month period ended June 30, 2012, Westar Energy entered into forward transactions pursuant to the forward sale agreement dated April 2, 2010 between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on April 2, 2010) and the Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.3 to the Form S-3 filed on April 2, 2010), as amended on May 26, 2010 (attached as Exhibit 1(a) hereto) and May 9, 2012 (filed as Exhibit 1(b) to the Form 10-Q filed on May 9, 2012), in respect to an aggregate of approximately 1.1 million shares of Westar Energy common stock.

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

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

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



1(a)		Amendment to Sales Agency Financing Agreement, dated May 26, 2010, among Westar Energy, Inc., BNY Mellon Capital Markets, LLC, and The Bank of New York Mellon
1(b)		Underwriting Agreement, dated May 14, 2012, among BNP Paribas Securities Corp., Citigroup Global Markets Inc. and J.P. Morgan Securities LLC, as representatives of the several underwriters named therein, and Westar Energy, Inc. (filed as Exhibit 1.1 to the Form 8-K filed on May 16, 2012)
1(c)		Form of Forty-Second Supplemental (Reopening) Indenture, dated as of May 17, 2012, by and between Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.1 to the Form 8-K filed on May 16, 2012)
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, 2012
31(b)		Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the period ended June 30, 2012
32		Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 certifying the quarterly report provided for the quarter ended June 30, 2012 (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

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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 7, 2012	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President and Chief Financial Officer/Treasurer