Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 2011	Apr. 27, 2011
Document and Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q1
Trading Symbol	wr
Entity Registrant Name	WESTAR ENERGY INC /KS
Entity Central Index Key	0000054507
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		113,690,101

Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 3,343	$ 928
Accounts receivable, net of allowance for doubtful accounts of $7,260 and $5,729, respectively	204,434	227,700
Inventories and supplies, net	220,642	206,867
Energy marketing contracts	5,996	13,005
Taxes receivable	22,459	16,679
Deferred tax assets	20,135	30,248
Prepaid expenses	16,068	12,413
Regulatory assets	67,379	73,480
Other	15,442	20,289
Total Current Assets	575,898	601,609
PROPERTY, PLANT AND EQUIPMENT, NET	6,038,935	5,964,439
OTHER ASSETS:
Regulatory assets	800,514	787,585
Nuclear decommissioning trust	133,102	126,990
Energy marketing contracts	9,064	9,472
Other	263,086	244,506
Total Other Assets	1,205,766	1,168,553
TOTAL ASSETS	8,162,756	8,079,638
CURRENT LIABILITIES:
Current maturities of long-term debt		61
Short-term debt	305,340	226,700
Accounts payable	178,870	187,954
Accrued taxes	68,261	45,534
Energy marketing contracts	2,845	9,670
Accrued interest	95,050	77,771
Regulatory liabilities	29,539	28,284
Other	157,297	176,717
Total Current Liabilities	864,060	782,846
LONG-TERM LIABILITIES:
Long-term debt, net	2,490,878	2,490,871
Deferred income taxes	1,114,611	1,102,625
Unamortized investment tax credits	100,670	101,345
Regulatory liabilities	142,899	135,754
Deferred regulatory gain from sale-leaseback	96,167	97,541
Accrued employee benefits	454,885	483,769
Asset retirement obligations	127,777	125,999
Energy marketing contracts		10
Other	61,933	66,878
Total Long-Term Liabilities	4,862,686	4,882,954
COMMITMENTS AND CONTINGENCIES (See Notes 8 and 9)
TEMPORARY EQUITY		3,465
Westar Energy Shareholders' Equity:
Cumulative preferred stock, par value $100 per share; authorized 600,000 shares; issued and outstanding 214,363 shares	21,436	21,436
Common stock, par value $5 per share; authorized 150,000,000 shares; issued and outstanding 113,587,852 shares and 112,128,068 shares, respectively	567,939	560,640
Paid-in capital	1,422,842	1,398,580
Retained earnings	418,230	423,647
Total Westar Energy Shareholders' Equity	2,430,447	2,404,303
Total Equity	2,436,010	2,410,373
TOTAL LIABILITIES AND EQUITY	8,162,756	8,079,638
Variable Interest Entity, Primary Beneficiary [Member]
CURRENT ASSETS:
PROPERTY, PLANT AND EQUIPMENT, NET	342,157	345,037
CURRENT LIABILITIES:
Current maturities of long-term debt	26,858	30,155
LONG-TERM LIABILITIES:
Long-term debt, net	272,866	278,162
Westar Energy Shareholders' Equity:
Noncontrolling Interests	$ 5,563	$ 6,070

Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets
Accounts receivable, allowance for doubtful accounts	$ 7,260	$ 5,729
Cumulative preferred stock, par value	$ 100	$ 100
Cumulative preferred stock, authorized	600,000	600,000
Cumulative preferred stock, issued	214,363	214,363
Cumulative preferred stock, outstanding	214,363	214,363
Common stock, par value	$ 5	$ 5
Common stock, authorized	150,000,000	150,000,000
Common stock, issued	113,587,852	112,128,068
Common stock, outstanding	113,587,852	112,128,068

Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
Consolidated Statements of Income
REVENUES	$ 481,720	$ 459,830
OPERATING EXPENSES:
Fuel and purchased power	134,184	133,800
Operating and maintenance	137,351	121,172
Depreciation and amortization	70,259	66,930
Selling, general and administrative	48,767	45,927
Total Operating Expenses	390,561	367,829
INCOME FROM OPERATIONS	91,159	92,001
OTHER INCOME (EXPENSE):
Investment earnings	1,968	1,757
Other income	2,249	854
Other expense	(5,368)	(4,494)
Total Other Expense	(1,151)	(1,883)
Interest expense	43,538	44,616
INCOME BEFORE INCOME TAXES	46,470	45,502
Income tax expense	13,513	13,820
NET INCOME	32,957	31,682
Less: Net income attributable to noncontrolling interests	1,373	1,002
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY	31,584	30,680
Preferred dividends	242	242
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$ 31,342	$ 30,438
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (See Note 2)	$ 0.27	$ 0.27
Average equivalent common shares outstanding	113,875,389	110,925,146
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.32	$ 0.31

Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$ 32,957	$ 31,682
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	70,259	66,930
Amortization of nuclear fuel	5,787	6,084
Amortization of deferred regulatory gain from sale-leaseback	(1,374)	(1,374)
Amortization of corporate-owned life insurance	6,308	5,840
Non-cash compensation	2,201	2,130
Net changes in energy marketing assets and liabilities	455	(181)
Accrued liability to certain former officers	647	504
Net deferred income taxes and credits	16,286	20,518
Stock-based compensation excess tax benefits	(629)	(277)
Allowance for equity funds used during construction	(1,752)	(455)
Changes in working capital items:
Accounts receivable	20,344	21,068
Inventories and supplies	(13,584)	(1,673)
Prepaid expenses and other	5,640	(3,260)
Accounts payable	(2,164)	10,001
Accrued taxes	17,123	11,382
Other current liabilities	(19,493)	(15,267)
Changes in other assets	(20,327)	7,758
Changes in other liabilities	(23,308)	(9,442)
Cash Flows from Operating Activities	95,376	151,968
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(155,945)	(103,272)
Purchase of securities within trust funds	(28,152)	(8,319)
Sale of securities within trust funds	27,582	7,628
Proceeds from investment in corporate-owned life insurance	512	448
Proceeds from federal grant	2,113
Investment in affiliated company	(381)	5
Other investing activities	2,198	690
Cash Flows used in Investing Activities	(152,073)	(102,820)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	78,640	(33,600)
Retirements of long-term debt	(191)	(646)
Repayment of capital leases	(444)	(610)
Borrowings against cash surrender value of corporate-owned life insurance	1,062	965
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(2,897)	(1,981)
Stock-based compensation excess tax benefits	629	277
Issuance of common stock, net	25,787	25,904
Cash dividends paid	(33,208)	(31,054)
Cash Flows from (used in) Financing Activities	59,112	(50,165)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2,415	(1,017)
CASH AND CASH EQUIVALENTS:
Beginning of period	928	3,860
End of period	3,343	2,843
Variable Interest Entity, Primary Beneficiary [Member]
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Retirements of long-term debt	(8,386)	(7,954)
Distributions to shareholders of noncontrolling interests	$ (1,880)	$ (1,466)

Consolidated Statements of Changes in Equity (USD $) In Thousands	Total	Cumulative preferred stock [Member]	Common stock [Member]	Paid-in capital [Member]	Retained earnings [Member]	Noncontrolling interests [Member]
Beginning Balance at Dec. 31, 2009	$ 2,266,785	$ 21,436	$ 545,360	$ 1,339,790	$ 360,199
Net income	31,682				30,680	1,002
Issuance of common stock, net	29,736		6,976	22,760
Preferred dividends	(242)				(242)
Dividends on common stock	(34,728)				(34,728)
Transfer to temporary equity	(6)			(6)
Amortization of restricted stock	1,653			1,653
Stock compensation and tax benefit	(1,667)			(1,667)
Consolidation of noncontrolling interests	3,435					3,435
Distributions to shareholders of noncontrolling interests	(1,466)					(1,466)
Ending Balance at Mar. 31, 2010	2,295,182	21,436	552,336	1,362,530	355,909	2,971
Beginning Balance at Dec. 31, 2010	2,410,373	21,436	560,640	1,398,580	423,647	6,070
Net income	32,957				31,584	1,373
Issuance of common stock, net	33,355		7,299	26,056
Preferred dividends	(242)				(242)
Dividends on common stock	(36,759)				(36,759)
Transfer to temporary equity	3,465			3,465
Amortization of restricted stock	1,653			1,653
Stock compensation and tax benefit	(6,912)			(6,912)
Distributions to shareholders of noncontrolling interests	(1,880)					(1,880)
Ending Balance at Mar. 31, 2011	$ 2,436,010	$ 21,436	$ 567,939	$ 1,422,842	$ 418,230	$ 5,563

Description of Business	3 Months Ended
Description of Business	Mar. 31, 2011
Description of Business
Description of Business	1. DESCRIPTION OF BUSINESS We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Quarterly Report on Form 10-Q to "the company," "we," "us," "our" and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term "Westar Energy" refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries. We provide electric generation, transmission and distribution services to approximately 687,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. 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.

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2011

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our unaudited condensed consolidated financial statements in accordance with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements presented in accordance with generally accepted accounting principles (GAAP) have been condensed or omitted. Our condensed consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single operating segment. Intercompany accounts and transactions have been eliminated in consolidation. In our opinion, all adjustments, consisting only of normal recurring adjustments considered necessary for a fair presentation of the consolidated financial statements, have been included.

The accompanying condensed consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in our 2010 Form 10-K.

Use of Management's Estimates

When we prepare our condensed consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis, including those related to bad debts, inventories, valuation of commodity contracts, depreciation, unbilled revenue, valuation of investments, valuation of our energy marketing portfolio, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and other post-retirement benefits, our asset retirement obligations including the decommissioning of Wolf Creek, environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions. The results of operations for the three months ended March 31, 2011, are not necessarily indicative of the results to be expected for the full year.

Allowance for Funds Used During Construction

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


	Three Months Ended March 31,
	2011			2010
	(Dollars in Thousands)
Borrowed funds	$	1,500		$	744
Equity funds		1,752			455

Total	$	3,252		$	1,199

Average AFUDC Rates		4.6	%		2.3	%

Earnings Per Share

We have participating securities related to unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends as declared on an equal basis with common shares. Therefore, we apply the two-class method of computing basic and diluted earnings per share (EPS).

Under the two-class method, we reduce net income attributable to common stock by the amount of dividends declared in the current period. We allocate the remaining earnings to common stock and RSUs to the extent that each security may share in earnings as if all of the earnings for the period had been distributed. We determine the total earnings allocated to each security by adding together the amount allocated for dividends and the amount allocated for a participation feature. To compute basic EPS, we divide the earnings allocated to common stock by the weighted average equivalent common shares outstanding. Diluted EPS includes the effect of potential issuances of common shares resulting from our forward sale agreements, RSUs that do not have nonforfeitable rights to dividend equivalents and stock options. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

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


	Three Months Ended March 31,
	2011		2010
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	32,957	$	31,682
Less: Net income attributable to noncontrolling interests		1,373		1,002

Net income attributable to Westar Energy		31,584		30,680
Less: Preferred dividends		242		242
Net income allocated to RSUs		147		126

Net income allocated to common stock	$	31,195	$	30,312

Weighted average equivalent common shares outstanding – basic		113,875,389		110,925,146
Effect of dilutive securities:
Restricted share units		186,312		27,427
Forward sale agreements		1,688,752		—
Employee stock options		—		207

Weighted average equivalent common shares outstanding – diluted (a)		115,750,453		110,952,780

Earnings per common share, basic and diluted	$	0.27	$	0.27

(a)	We did not have any antidilutive shares for the three months ended March 31, 2011 and 2010.

Supplemental Cash Flow Information


	Three Months Ended March 31,
	2011		2010
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	28,413	$	29,065
Interest on financing activities of VIEs		9,024		9,891
Income taxes, net of refunds		753		2,013
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions		55,448		23,332
Property, plant and equipment additions of VIEs		—		356,964
Jeffrey Energy Center (JEC) 8% leasehold interest		—		(108,706	)
NON-CASH FINANCING TRANSACTIONS:
Issuance of common stock for reinvested dividends and compensation plans		5,146		3,536
Debt of VIEs		—		337,951
Capital lease for JEC 8% leasehold interest		—		(106,423	)
Assets acquired through capital leases		208		—

Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management

3 Months Ended

Mar. 31, 2011

Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management

Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management

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

Values of Financial and Derivative Instruments

GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of fair value assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:

•

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

•

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

•

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

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

All of our level 2 investments, whether in the nuclear decommissioning trust (NDT) or our trading securities portfolio, are held in investment funds that are measured using daily net asset values as reported by the fund managers. In addition, we maintain certain level 3 investments in private equity and real estate securities that require significant unobservable market information to measure the fair value of the investments. The fair value of private equity investments is measured by utilizing both market- and income-based models, public company comparables, at cost or at the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. To measure the fair value of real estate securities we use a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

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

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our financial instruments as of March 31, 2011, and December 31, 2010.


	As of March 31, 2011				As of December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	2,373,243	$	2,552,207	$	2,373,373	$	2,570,648
Fixed-rate debt of VIEs		297,511		308,501		308,317		341,328

Recurring Fair Value Measurements

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


	Level 1		Level 2		Level 3		Total
	(In Thousands)
As of March 31, 2011
Assets:
Energy Marketing Contracts	$	—	$	1,849	$	13,211	$	15,060
Nuclear Decommissioning Trust:
Domestic equity		—		54,063		3,058		57,121
International equity		—		27,355		—		27,355
Core bonds		—		22,240		—		22,240
High-yield bonds		—		9,573		—		9,573
Emerging market bonds		—		5,755		—		5,755
Combination debt/equity fund		—		7,952		—		7,952
Real estate securities		—		—		3,049		3,049
Cash equivalents		57		—		—		57

Total Nuclear Decommissioning Trust		57		126,938		6,107		133,102

Trading Securities:
Domestic equity		—		21,808		—		21,808
International equity		—		5,284		—		5,284
Core bonds		—		14,266		—		14,266

Total Trading Securities		—		41,358		—		41,358

Treasury Yield Hedges		—		10,334		—		10,334

Total Assets Measured at Fair Value	$	57	$	180,479	$	19,318	$	199,854

Liabilities:
Energy Marketing Contracts	$	—	$	1,640	$	1,205	$	2,845

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

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

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

Total Trading Securities		—		39,412		—		39,412

Treasury Yield Hedges		—		7,711		—		7,711

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

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

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

The following table provides reconciliations of assets and liabilities measured at fair value using significant level 3 inputs for the three months ended March 31, 2011 and 2010.


	Energy Marketing Contracts, net			Nuclear Decommissioning Trust									Net Balance
	Energy Marketing Contracts, net			Domestic Equity			High-yield Bonds			Real Estate Securities			Net Balance
	(In Thousands)
Balance as of December 31, 2010	$	11,815		$	2,867		$	305		$	3,049		$	18,036
Total realized and unrealized gains (losses) included in:
Earnings (a)		(197	)		—			—			—			(197	)
Regulatory assets		(18	)(b)		—			—			—			(18	)
Regulatory liabilities		599	(b)		31			—			—			630
Purchases		(742	)		173			—			—			(569	)
Sales		894			(13	)		(305	)		—			576
Settlements		(345	)		—			—			—			(345	)

Balance as of March 31, 2011	$	12,006		$	3,058		$	—		$	3,049		$	18,113

Balance as of December 31, 2009	$	4,310		$	2,262		$	5,741		$	3,635		$	15,948
Total realized and unrealized gains (losses) included in:
Earnings (a)		4			—			—			—			4
Regulatory assets		4,468	(b)		—			—			—			4,468
Regulatory liabilities		3,286	(b)		82			238			(856	)		2,750
Purchases, issuances and settlements		2,384			40			—			—			2,424

Balance as of March 31, 2010	$	14,452		$	2,384		$	5,979		$	2,779		$	25,594

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

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

A portion of the gains and losses contributing to changes in net assets in the above table is unrealized. The following table summarizes the unrealized gains and losses we recorded on our consolidated financial statements during the three months ended March 31, 2011 and 2010, attributed to level 3 assets and liabilities.


	Three Months Ended March 31, 2011
	Energy Marketing Contracts, net			Nuclear Decommissioning Trust							Net Balance
	Energy Marketing Contracts, net			Domestic Equity		High-yield Bonds		Real Estate Securities			Net Balance
	(In Thousands)
Total unrealized gains (losses) included in:
Earnings (a)	$	(273	)	$	—	$	—	$	—		$	(273	)
Regulatory assets		(10	)(b)		—		—		—			(10	)
Regulatory liabilities		601	(b)		19		—		—			620

Total	$	318		$	19	$	—	$	—		$	337


	Three Months Ended March 31, 2010
Total unrealized gains (losses) included in:
Earnings (a)	$	(197	)	$	—	$	—	$	—		$	(197	)
Regulatory assets		4,540	(b)		—		—		—			4,540
Regulatory liabilities		3,251	(b)		82		238		(856	)		2,715

Total	$	7,594		$	82	$	238	$	(856	)	$	7,058

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

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

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


	As of March 31, 2011				As of December 31, 2010				As of March 31, 2011
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency		Length of Settlement
	(In thousands)
Nuclear Decommissioning Trust:
Domestic equity	$	3,058	$	2,350	$	2,867	$	2,523		(a)		(a)
High-yield bonds		—		—		305		—		(b)		(b)
Real estate securities		3,049		—		3,049		—		(c)		(c)

Total Nuclear Decommissioning Trust	$	6,107	$	2,350	$	6,221	$	2,523

Trading Securities:
Domestic equity	$	21,808	$	—	$	21,207	$	—		Upon Notice		1 day
International equity		5,284		—		5,128		—		Upon Notice		1 day
Core bonds		14,266		—		13,077		—		Upon Notice		1 day

Total Trading Securities		41,358		—		39,412		—

Total	$	47,465	$	2,350	$	45,633	$	2,523

(a)

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

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

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

Derivative Instruments

Cash Flow Hedges

In 2010, we entered into treasury yield hedge transactions for a total notional amount of $100.0 million in order to manage our interest rate risk associated with a future anticipated issuance of fixed-rate debt, which is probable to occur within 18 months of the initial treasury yield hedge transaction date. Such transactions are designated and qualify as cash flow hedges and are measured at fair value by estimating the net present value of a series of payments using market-based models with observable inputs, such as the spread between the 30-year U.S. Treasury bill yield and the contracted, fixed yield. As a result of regulatory accounting treatment, we report the effective portion of the gain or loss on these derivative instruments as a regulatory liability or regulatory asset and will amortize such amounts to interest expense over the life of the related debt. We record hedge ineffectiveness gains in other income and hedge ineffectiveness losses in other expense on our consolidated statements of income. As of March 31, 2011, and December 31, 2010, the fair value of the treasury yield hedge transactions was $10.3 million and $7.7 million, respectively, which we recorded in other assets on our consolidated balance sheets. We also recorded these same amounts in long-term regulatory liabilities on our consolidated balance sheets to reflect the effective portion of the gains on these transactions as of March 31, 2011, and December 31, 2010.

Commodity Contracts

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

We classify these commodity derivative instruments as energy marketing contracts on our consolidated balance sheets. We report energy marketing contracts representing unrealized gain positions as assets; energy marketing contracts representing unrealized loss positions are reported as liabilities. With the exception of certain fuel supply and electricity contracts, which we record as regulatory assets or regulatory liabilities, we include the change in the fair value of energy marketing contracts in revenues on our consolidated statements of income.

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

Commodity Derivatives Not Designated as Hedging Instruments as of March 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	$	5,996	Energy marketing contracts	$	2,845
Other assets:
Energy marketing contracts		9,064

Total	$	15,060

Commodity Derivatives Not Designated as Hedging Instruments as of December 31, 2010


Asset Derivatives			Liability Derivatives
Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(In thousands)			(In thousands)
Current assets:			Current liabilities:
Energy marketing contracts	$	13,005	Energy marketing contracts	$	9,670
Other assets:			Long-term liabilities:
Energy marketing contracts		9,472	Energy marketing contracts		10

Total	$	22,477	Total	$	9,680

The following table presents how changes in the fair value of commodity derivative instruments affected our consolidated financial statements for the three months ended March 31, 2011 and 2010.


	Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Location	Net Loss Recognized			Net Gain Recognized			Net Loss Recognized
	(In thousands)
Revenues decrease	$	(1,555	)	$	—		$	(565	)
Regulatory assets decrease		—			(7,193	)		—
Regulatory liabilities (decrease) increase		(213	)		3,380			—

As of March 31, 2011, and December 31, 2010, we had under contract the following energy-related products.

Unit of
Measure

Net Quantity as of

March 31, 2011

December 31, 2010

Electricity

MWh

2,913,347

2,791,966

Natural Gas

MMBtu

1,515,000

1,150,000

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

Energy Marketing Activities

Within our energy trading portfolio, we may establish certain positions intended to economically hedge a portion of physical sale or purchase contracts and we may enter into certain positions attempting to take advantage of market trends and conditions. We use the term economic hedge to mean a strategy intended to manage risks of volatility in prices or rate movements on selected assets, liabilities or anticipated transactions by creating a relationship in which gains or losses on derivative instruments are expected to offset the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks.

Price Risk

We use various types of fuel, including coal, natural gas, uranium, diesel and oil, to operate our plants and purchase power to meet customer demand. Our prices, consolidated financial results and cash flows are exposed to market risks from commodity price changes for electricity and other energy-related products and interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers' and our exposure to these market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

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

Credit Risk

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

We have derivative instruments with commodity exchanges and other counterparties that do not contain objective credit-risk-related contingent features. However, certain of our derivative instruments contain collateral provisions subject to credit agency ratings of our senior unsecured debt. If our senior unsecured debt ratings were to decrease or fall below investment grade, the counterparties to the derivative instruments, pursuant to the provisions, could require collateralization on derivative instruments. The aggregate fair value of all derivative instruments with objective credit-risk-related contingent features that were in a liability position as of March 31, 2011, and December 31, 2010, was $0.8 million and $1.6 million, respectively, for which we had posted $0.5 million of collateral, including independent amounts, as of March 31, 2011, and no collateral as of December 31, 2010. If all credit-risk-related contingent features underlying these agreements had been triggered as of March 31, 2011, and December 31, 2010, we would have been required to provide to our counterparties $0.7 million and $1.6 million, respectively, of additional collateral after taking into consideration the offsetting impact of derivative assets and net accounts receivable.

Financial Investments

3 Months Ended

Mar. 31, 2011

Financial Investments

Financial Investments

4. FINANCIAL INVESTMENTS

We report some of our investments in debt and equity securities at fair value. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We have equity and debt investments in a trust used to fund retirement benefits that we classify as trading securities. We include any unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. We recorded unrealized gains of $1.5 million and $1.6 million, respectively, during the three months ended March 31, 2011 and 2010.

Available-for-Sale Securities

We hold investments in equity, debt and real estate securities in a trust fund for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of March 31, 2011, and December 31, 2010. At March 31, 2011, investments in the NDT fund were allocated 43% to domestic equity, 21% to international equity, 17% to core bonds, 7% to high-yield bonds, 4% to emerging market bonds, 6% to combined debt/equity funds, 2% to real estate securities and less than 1% to cash and cash equivalents. The core bond fund is limited to ensure that at least 80% of funds are invested in investment grade U.S. corporate and government fixed income securities, including mortgage-backed securities. As of March 31, 2011, the fair value of the debt securities in the NDT fund was $37.6 million, held entirely in bond funds.

Using the specific identification method to determine cost, we realized gains on our available-for-sale securities of $0.9 million during the three months ended March 31, 2011 and 2010. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

The following table presents the costs and fair values of investments in the NDT fund as of March 31, 2011, and December 31, 2010.


	Cost		Gross Unrealized					Fair Value
Security Type	Cost		Gain		Loss			Fair Value
	(In Thousands)
As of March 31, 2011:
Domestic equity	$	50,213	$	7,000	$	(92	)	$	57,121
International equity		24,774		2,581		—			27,355
Core bonds		22,235		5		—			22,240
High-yield bonds		9,170		403		—			9,573
Emerging market bonds		5,501		254		—			5,755
Combination debt/equity fund		7,737		215		—			7,952
Real estate securities		6,207		—		(3,158	)		3,049
Cash equivalents		57		—		—			57

Total	$	125,894	$	10,458	$	(3,250	)	$	133,102

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

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

The following table presents the fair value and gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of March 31, 2011, and December 31, 2010.


	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of March 31, 2011:
Domestic equity	$	3,058	$	(92	)	$	—	$	—		$	3,058	$	(92	)
Real estate securities		—		—			3,049		(3,158	)		3,049		(3,158	)

Total	$	3,058	$	(92	)	$	3,049	$	(3,158	)	$	6,107	$	(3,250	)

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

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

Rate Matters and Regulation	3 Months Ended
Rate Matters and Regulation	Mar. 31, 2011
Rate Matters and Regulation
Rate Matters and Regulation	5. RATE MATTERS AND REGULATION FERC Proceedings Our transmission formula rate that includes projected 2011 transmission capital expenditures and operating costs became effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million. This updated rate provides the basis for our request with the Kansas Corporation Commission (KCC) to adjust our retail prices to include updated transmission costs.

Short-Term Debt	3 Months Ended
Short-Term Debt	Mar. 31, 2011
Short-Term Debt
Short-Term Debt	6. SHORT-TERM DEBT Westar Energy has a $730.0 million revolving credit facility with a syndicate of banks that terminates on March 17, 2012. As of March 31, 2011, $305.3 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2010, $226.7 million had been borrowed and an additional $21.5 million of letters of credit had been issued under this revolving credit facility. In February 2011, Westar Energy entered into a new revolving credit facility with a similar syndicate of banks for an additional $270.0 million. The commitments under this facility terminate in February 2015. As of March 31, 2011, Westar Energy had neither borrowed monies nor issued letters of credit under this revolving credit facility.

Taxes	3 Months Ended
Taxes	Mar. 31, 2011
Taxes
Taxes	7. TAXES We recorded income tax expense of $13.5 million with an effective income tax rate of 29% for the three months ended March 31, 2011. We recorded income tax expense of $13.8 million with an effective income tax rate of 30% for the same period of 2010. The decrease in the effective income tax rate for the three months ended March 31, 2011, was due primarily to increases in the tax benefits from AFUDC equity and increases in production tax credits. At March 31, 2011, and December 31, 2010, our liability for unrecognized income tax benefits was $3.8 million and $1.9 million, respectively. The net increase in the liability for unrecognized income tax benefits was largely attributable to tax positions taken with respect to the capitalization of plant related expenditures. We do not expect any significant changes in this liability in the next 12 months. As of March 31, 2011, and December 31, 2010, we had $0.4 million accrued for interest on our liability related to unrecognized income tax benefits. We accrued no penalties at either March 31, 2011, or December 31, 2010. As of March 31, 2011, and December 31, 2010, we had recorded $3.6 million for probable assessments of taxes other than income taxes.

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2011
Commitments and Contingencies
Commitments and Contingencies	8. COMMITMENTS AND CONTINGENCIES Federal Clean Air Act We must comply with the Federal Clean Air Act, state laws and implementing regulations that impose, among other things, limitations on pollutants generated during our operations, including sulfur dioxide (SO₂), particulate matter, nitrogen oxides (NOx) and mercury. In addition, we must comply with the provisions of the Federal Clean Air Act Amendments of 1990 that require reductions in SO₂and NOx. Emissions from our generating facilities, including particulate matter, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE), we are required to install and maintain controls to reduce emissions found to cause or contribute to regional haze. Under the Federal Clean Air Act, the Environmental Protection Agency (EPA) sets National Ambient Air Quality Standards (NAAQS) for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO₂, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We are currently evaluating what impact this could have on our operations. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results. Environmental Projects We will continue to make significant capital expenditures at our power plants to reduce regulated emissions. The amount of these expenditures could change materially depending on the timing and nature of required investments, the specific outcomes resulting from interpretation of existing regulations, new regulations, legislation and the manner in which we operate the plants. In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expense and may reduce the net production, reliability and availability of the plants. The degree to which we will need to reduce emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and ultimate amount of such capital investments. The environmental cost recovery rider (ECRR) allows for the more timely inclusion in retail prices of the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. In order to change our prices to recognize increased operating and maintenance costs, however, we must file a general rate case with the KCC. The KCC has indicated that it believes environmental costs at La Cygne Generating Station (La Cygne) may be more appropriate to recover through the filing of a general rate case as opposed to the ECRR. This could increase the time between making these investments and having them reflected in the prices we charge our customers, as well as the amount we charge our customers, and could affect our capital expenditure plans. This matter has not yet been resolved. Greenhouse Gases Under EPA regulations finalized in May 2010, known as the tailoring rule, the EPA began regulating greenhouse gas (GHG) emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two Federal Clear Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement best available control technology (BACT). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these new regulations on our operations and consolidated financial results, but we believe the cost of compliance with new regulations could be material. Renewable Energy Standard In May 2009, Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. In years 2011 through 2015 net renewable generation capacity must be 10% of the average peak demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. We have worked with third parties to develop approximately 300 MW of qualifying wind generation facilities, which together with the use of renewable energy credits, we expect to meet the 2011 requirement. On December 14, 2010, we announced that we reached two separate agreements with third parties, subject to regulatory approval, to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of wind generation beginning in late 2012. We expect these agreements, along with our prior development of wind generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in 2016. Manufactured Gas Sites We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and KDHE entered into a consent agreement governing all future work at these sites. Under terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK Inc. (ONEOK), ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million. EPA Lawsuit In March 2010, the U.S. District Court in the District of Kansas approved a settlement agreement that we entered into with the parties of a lawsuit filed by the Department of Justice on behalf of the EPA. The lawsuit asserted that certain projects completed at JEC violated certain requirements of the EPA's New Source Review program, which requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions. As part of the settlement agreement, in 2009 we recorded $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and a $3.0 million civil penalty. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In addition, we will install a selective catalytic reduction (SCR) on one of the three JEC coal units by the end of 2014. We estimate the cost of this to be approximately $240.0 million. This amount could change materially depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, we may have to install an SCR on another JEC unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge customers. FERC Investigation A non-public investigation by the Federal Energy Regulatory Commission (FERC) of our use of transmission service between July 2006 and February 2008 remains pending. In May 2009, FERC staff advised us that it had preliminarily concluded that we improperly used secondary network transmission service to facilitate off-system wholesale power sales in violation of applicable FERC orders and Southwest Power Pool (SPP) tariffs. FERC staff alleged we received $14.3 million of unjust profits through such activities. We sent a response to FERC staff disputing both the legal basis for its allegations and their factual underpinnings. Based on our response, FERC staff substantially revised downward its preliminary conclusions to allege that we received $3.0 million of unjust profits and failed to pay $3.2 million to the SPP for transmission service. In March 2010, we sent a response to FERC staff disputing its revised conclusions. We continue to believe that our use of transmission service was in compliance with FERC orders and SPP tariffs. We are unable to predict the outcome of this investigation or its impact on our consolidated financial results, but an adverse outcome could result in refunds and fines, the amounts of which could be material, and could potentially alter the manner in which we are permitted to buy and sell energy and use transmission service.

Legal Proceedings	3 Months Ended
Legal Proceedings	Mar. 31, 2011
Legal Proceedings
Legal Proceedings	9. LEGAL PROCEEDINGS In late 2002, one of our former executive officers resigned from his position and another executive officer was placed on administrative leave from his position. Following the completion of an investigation and the publication of a report prepared by a special committee of our board of directors, our board of directors determined that their employment was terminated for cause. In June 2003, we filed a demand for arbitration with the American Arbitration Association asserting claims against them arising out of their previous employment and seeking to avoid payment of compensation not yet paid to them under various plans and agreements. They filed counterclaims against us alleging substantial damages related to the termination of their employment and the publication of the report of the special committee. As of March 31, 2011, we had accrued liabilities of $81.4 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. As of December 31, 2010, we had accrued liabilities of $80.6 million for compensation not yet paid to them and $8.3 million for legal fees and expenses they had incurred. The arbitration was stayed in August 2004 pending final resolution of criminal charges filed by the United States Attorney's Office against them in U.S. District Court in the District of Kansas. In August 2010, these criminal charges were dismissed and subsequently the stay of the arbitration was lifted. We expect arbitration proceedings to conclude in 2011. While we intend to vigorously defend against the counterclaims they filed in the arbitration, we are exploring alternatives to settle all claims related to these executives. We are unable to predict the ultimate amount of the compensation, legal fees or related amounts we may be required to pay them, or the ultimate impact of these matters on our consolidated financial results. We and our subsidiaries are involved in various other legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material adverse affect on our consolidated financial results. See Note 5, "Rate Matters and Regulation," and Note 8, "Commitments and Contingencies," for additional information.

Interim Pension and Post-Retirement Benefit Disclosure

3 Months Ended

Mar. 31, 2011

Interim Pension and Post-Retirement Benefit Disclosure

Interim Pension and Post-Retirement Benefit Disclosure

10. INTERIM PENSION AND POST-RETIREMENT BENEFIT DISCLOSURE

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2011			2010			2011			2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	4,017		$	3,518		$	452		$	433
Interest cost		9,955			9,842			1,692			1,788
Expected return on plan assets		(7,772	)		(9,597	)		(1,200	)		(1,360	)
Amortization of unrecognized:
Transition obligation, net		—			—			978			978
Prior service costs		303			667			539			544
Actuarial loss, net		5,915			4,245			254			101

Net periodic cost before regulatory adjustment		12,418			8,675			2,715			2,484
Regulatory adjustment		(5,625	)		(3,121	)		297			430

Net periodic cost	$	6,793		$	5,554		$	3,012		$	2,914

During the three months ended March 31, 2011 and 2010, we contributed $29.0 million and $8.4 million, respectively, to the Westar Energy pension trust.

- Definition

Description containing the entire pension and other postretirement benefits disclosure as a single block of text.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 158

-Paragraph 7, 21, 22

Reference 2: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5, 6, 7, 8

Reference 3: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 8

-Subparagraph m

Reference 4: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 106

-Paragraph 518

Reference 5: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 87

-Paragraph 264

Reference 6: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph b

Reference 7: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph a

Reference 8: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph h

Reference 9: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 132R

-Paragraph 5

-Subparagraph q

Reference 10: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name FASB Staff Position (FSP)

-Number FAS106-2

-Paragraph 20, 21, 22

Reference 11: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Emerging Issues Task Force (EITF)

-Number 03-2

-Paragraph 8

Reference 12: http://www.xbrl.org/2003/role/presentationRef

-Publisher AICPA

-Name Accounting Principles Board Opinion (APB)

-Number 30

-Paragraph 26

Reference 13: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Implementation Guide (Q and A)

-Number FAS88

-Paragraph 63

+ Details

Wolf Creek Interim Pension and Post-Retirement Benefit Disclosure

3 Months Ended

Mar. 31, 2011

Wolf Creek Interim Pension and Post-Retirement Benefit Disclosure

Wolf Creek Interim Pension and Post-Retirement Benefit Disclosure

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

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


	Pension Benefits						Post-retirement Benefits
Three Months Ended March 31,	2011			2010			2011		2010
	(In Thousands)
Components of Net Periodic Cost:
Service cost	$	1,260		$	1,024		$	54	$	54
Interest cost		1,864			1,724			126		130
Expected return on plan assets		(1,525	)		(1,380	)		—		—
Amortization of unrecognized:
Transition obligation, net		13			14			14		14
Prior service costs		4			7			8		—
Actuarial loss, net		995			606			76		69

Net periodic cost before regulatory adjustment		2,611			1,995			278		267
Regulatory adjustment		(657	)		(322	)		—		—

Net periodic cost	$	1,954		$	1,673		$	278	$	267

During the three months ended March 31, 2011 and 2010, we funded $5.7 million and $0.9 million, respectively, of Wolf Creek's pension plan contribution.

Common Stock Issuance	3 Months Ended
Common Stock Issuance	Mar. 31, 2011
Common Stock Issuance
Common Stock Issuance	12. COMMON STOCK ISSUANCE On February 15, 2011, Westar Energy delivered approximately 1.1 million shares of common stock and received proceeds of $25.8 million as partial settlement of the forward sale agreement entered into with a bank in April 2010. Assuming physical share settlement of the approximately 3.1 million remaining shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $68.5 million, net of commission, based on an average forward price of $21.86 per share. During the three months ended March 31, 2011, Westar Energy did not deliver any shares of common stock under the forward sale agreement entered into with a bank in November 2010. Assuming physical share settlement of the approximately 8.5 million shares of common stock under this agreement at March 31, 2011, Westar Energy would have received aggregate proceeds of approximately $203.4 million, net of commission, based on an average forward price of $23.98 per share.

Variable Interest Entities

3 Months Ended

Mar. 31, 2011

Variable Interest Entities

Variable Interest Entities

13. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity's purpose and design, including the nature of the entity's activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in JEC, our 50% interest in La Cygne unit 2 and railcars we use to transport coal to some of our plants are VIEs of which we are the primary beneficiary.

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

8% Interest in Jeffrey Energy Center

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

50% Interest in La Cygne Unit 2

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

Railcars

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

Financial Statement Impact

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


	As of March 31, 2011		As of December 31, 2010
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	342,157	$	345,037
Regulatory asset (a)		4,278		3,963

Liabilities:
Current maturities of long-term debt of variable interest entities	$	26,858	$	30,155
Accrued interest (b)		573		5,064
Long-term debt of variable interest entities, net		272,866		278,162

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

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

- Definition

Disclosure of variable interest entities (VIE), including, but not limited to the nature, purpose, size, and activities of the VIE, the carrying amount and classification of consolidated assets that are collateral for the VIE's obligations, lack of recourse if creditors (or beneficial interest holders) of a consolidated VIE have no recourse to the general credit of the primary beneficiary. An enterprise that holds a significant variable interest in a VIE but is not the primary beneficiary may disclose the nature of its involvement with the VIE and when that involvement began, the nature, purpose, size, and activities of the VIE and the enterprise's maximum exposure to loss as a result of its involvement with the VIE.

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